bluuebunny/crossref_metadata_2025_split huggingface dataset:
Guest Editorial: How a Healthy Work Environment Drives a Healthy P&L
Authors: Harriman Matt 
Published: August 2023

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People who are passionate about running businesses often talk about money or people—but not both.
Imagine, a chief operating officer at an oil company who doesn’t listen to any ideas that won’t result in more barrels or more money, right now. Many of us in the oil and gas industry know what it feels like to work in that organization.
Or the human resources leader that puts together an offsite meeting with personality tests, teambuilding exercises, and some “feel-good” work that has nothing to do with the actual work of the company.
Both examples have their place and their value, but they never work well together. It’s one or the other.
This is because of a widespread belief that what is right for a business and what is right for the people that work within one are inherently in conflict with each other.
At best, people view them as opposing forces to balance. At worst, they’re seen as incompatible ideas and there’s no town big enough for the both of them.
I call nonsense.

What’s Good for People? Elimination of Frustration
Whether it’s the fabled “TPS Reports,” jammed printers, or (multiple) inept bosses, we all have things at work that make our days worse. Some of them are minor annoyances like an extra copy/paste step, but many of them cause damage to our focus, ability to make decisions, and overall efficacy at our jobs.
What is one of the worst? Poor communication. Usually, small teams are not too bad at communication. But cross-department collaboration (or the lack thereof) is almost always an area where companies of all sizes can find room for improvement.

Give Them a Reason To Care
Obviously pay and benefits are a good reason to care about your work. But there is a big difference in your attitude if you are simply “here so I don’t get fired” vs. truly caring about your work, your company, and the people you work with.
This is what people mean when they talk about “employee engagement.”
What makes someone care about their work beyond a paycheck? It varies, but here are a few high-probability ideas:
- Ensuring they understand the impact of their work on the big picture.
- Supporting their personal growth goals, i.e., leadership growth, skill development, new challenges.
- Fostering a fair work environment. Involve employees in decisions for the company.

What’s Good for Business? A Smooth Process
A process that is effective, efficient, and integrated and one that is “not too bad” are worlds apart.
Everyone knows that process problems cause wasted time and resources. But many people underestimate the real cost—the missed upside. That time spent dealing with bad process is time that should have been spent driving better decisions or improving the business. If you make good people do both by working more than they want to, they will leave.
And here’s a hint to the punchline: improving a process looks a lot like eliminating frustrations.
BP’s Argos FPU Offers Fresh Lessons for the Future of Deepwater GOM Projects
Authors: Wright Blake 
Published: August 2023

Tipping the scales at well over 60,000 tons, BP’s Argos platform is a giant among giants in the deepwater US Gulf of Mexico (GOM). Standing 27 stories tall, the platform has a deck the length and width of an American football field and is one of BP’s largest in the region. One-time KBR subsidiary GVA designed the semisubmersible, the centerpiece of the supermajor’s $9 billion Mad Dog II project built to unlock additional production potential of the Miocene-aged reservoirs estimated to hold more than 5 billion bbl of oil in place.
But that wasn’t always the plan.
Over a decade ago, BP’s Mad Dog II looked quite different. On paper, the producer was looking at an all-subsea development tied back to another large spar platform—dubbed Big Dog—to host the additional reserves. The development plan envisioned a massive truss spar. Its topsides would need to be installed via three separate offshore lifts then fully integrated at the field site. Any offshore heavy lift is an execution risk. In 1998, an accident while lifting the south module onto Texaco’s Petronius compliant tower in the GOM resulted in the loss of that section of the topsides and delayed the project for a year and a half. That module weighed 3,600 tons.
Another hesitation for BP? The price tag. All-in, the spar-based Mad Dog II solution was estimated to cost around $19 billion. That included 30-plus wells. Ultimately, the spar concept was scrapped, and BP moved back to square one and a blank sheet of paper.
“The reserves were there,” said Chris Ruthven, project general manager, Mad Dog II. “We knew the reserves were there. In fact, ironically, the team developed the field with the smallest of the four big platforms that BP did back at that point in time: Thunder Horse, Holstein, Atlantis, and Mad Dog. It was the smallest, but ultimately, it was the second-biggest field. It turned out to be huge. All that appraisal showed we’ve got a lot of reserves. So, we went back and went with an analog to Atlantis. Atlantis was seen as a good fit requiring much less offshore integration work. Operations loved the asset, and it was a very safe design. We landed on that concept, and we tried to keep it almost pretty much the same in terms of the overall layout of the facility, but it’s a little bit bigger footprint.”
Mad Dog proper was discovered in 1998 via an exploration well in over 6,100 ft of water located in Green Canyon Block 826. The well was drilled to a measured depth of 22,410 ft and encountered around 215 ft of hydrocarbon-bearing Miocene reservoirs. The discovery was followed by a 1999 well drilled to a total depth of 22,410 ft and a further successful appraisal well in February 2000.
Mad Dog, covering Green Canyon blocks 825, 826, and 782, was sanctioned as a spar-based development in 2002. The project came online in early 2005.
Technology Focus: Reservoir Simulation (July 2023)
Authors: Abraham Anson 
Published: August 2023

As 2022 drew to a close, we saw the emergence of ChatGPT, a development that left me both fascinated and slightly apprehensive. Initial posts on LinkedIn and similar platforms focused on its impressive capabilities, yet it wasn’t long before discussions of its inherent biases began to surface.
Artificial intelligence (AI) and machine learning (ML) technologies have rapidly progressed and have significantly affected traditional reservoir engineering, bringing innovative methodologies to reservoir simulations. However, it is essential to understand that these AI and ML technologies are only as effective and trustworthy as the data they are trained on. Limiting the data we feed these systems might inadvertently restrict their predictive power and the scope of their solutions.
As we increasingly rely on these data-driven tools for decision-making, we must be cautious of the conclusions they draw and the narratives they generate. These can subtly shape our viewpoints, highlighting the need for a firm understanding of fundamental principles. I am reminded of a term coined by Daniel Yang: the “Nintendo Engineer,” an engineer whose thought process is guided by simulations rather than the other way around.
With this in mind, returning to the foundational principles underpinning our field is crucial. This approach could counterbalance our reliance on AI and ML technologies, helping us maintain a well-rounded perspective.
The papers I am recommending for your reading embody this mindset.
The first paper highlights these technologies’ practical challenges and constraints, offering valuable insights for reservoir engineers. The authors emphasize the need for a balanced approach that combines these advanced techniques with informed decision-making.
They also highlight that only some optimization problems can be solved with a plug-and-play approach and that the engineer has to frame the problem in a manageable and meaningful way.
The second paper addresses the limitations of the conventional Stone II three-phase permeability model and presents a novel, robust alternative. It takes a fundamentals-based approach to develop an alternative model for the three-phase relative permeability model. Inherent in this recommendation is my bias toward heavy oil because it is the area I currently work in.
The third paper showcases the remarkable potential of AI in supplementing traditional reservoir simulation. The paper’s real-world application demonstrates the practicality and adaptability of AI in reservoir engineering and simulation.
I hope you enjoy reading this selection of papers and find them enlightening.
Recommended additional reading at OnePetro: www.onepetro.org.
URTEC 2021-5549 Use of Machine Learning Production Driver Cross Sections for Regional Geologic Insights in the Bakken Three Forks Play by T. Cross, Novi Labs, et al.
SPE 214219 Business Intelligence Dashboarding Application in Reservoir Simulation by Ke Wang, ADNOC, et al.
Approach Improves Vertical and Areal Sweep in Tengiz Platform Sour-Gas Injection
Authors: Carpenter Chris 
Published: August 2023

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203995, “Injection and Production Optimization for Tengiz Platform Sour-Gas Injection by Reactive and Proactive Conformance Completions Control,” by Shusei Tanaka, SPE, and Matthieu Rousset, SPE, Chevron, and Yousef Ghomian, SPE, Tengizchevoil, et al. The paper has not been peer reviewed.

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Sour-gas injection (SGI) operations have been implemented in the Tengiz field since 2008 and will be expanded in a future project. Because of limited gas-handling capacity, production at a high gas/oil ratio (GOR) has posed a challenge, resulting in potential well shutdowns. The objective of the study described in the complete paper was to establish an efficient optimization work flow to improve vertical and areal sweep, thereby maximizing recovery under operational constraints. This will be achieved through conformance-control completions that have been installed in many production and injection wells.

Introduction
The Tengiz field is in northwestern Kazakhstan on the northeast shore of the Caspian Sea. The reservoir extends 20 km2 with an oil column of approximately 1.6 km in a carbonate buildup structure at 3850 m subsea. Tengiz produced oil has a specific gravity of 47 °API with approximately 13% of hydrogen sulfide (H2S) and 3% CO2 in produced gas. At initial reservoir conditions, the GOR was 2,242 scf/STB and oil viscosity was 0.22 cp. At the time of writing, the production strategy follows gas-injection processes in the central to north platform area while depletion drive exists at the platform margin to the slope, where fractures appear to dominate flow dynamics. The production area is maintained above saturation pressure based on surveillance data for both the platform and slope zones.

Tengiz SGI With Vertical Conformance Control
The authors write that 20% of produced gas at Tengiz field is reinjected into the central platform area, which consists of the Bashkirian (Bash), Serpukhovian (Serp), and Visean A (VisA) formations. As the volume of injected gas increases, the neighboring producers observe gas breakthrough with increased GOR. The high-GOR wells need to be shut in to achieve maximum oil production in the plant. As the number of shut-in wells increases, however, it becomes challenging to meet plant capacity because of a lack of active producers, resulting in loss of production.
To avoid production loss, zonal-production and injection-control capability were introduced through conformance-control completions and use of swell packers and sliding sleeves. With completions closed at a high-GOR interval, oil production is expected to be maintained while gas production from the well is reduced.
With the extension of the SGI project, capability will exist to control vertical conformance with the planned completion strategy in 38 producers. In addition, 17 injectors also will have vertical conformance-control capability for selective zonal injections.
Mangrove Restoration and Conservation Effort in Niger Delta Used as Carbon Offset Option
Authors: Carpenter Chris 
Published: August 2023

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 207725, “Mangrove Restoration and Conservation as a Carbon Offset Option: a Case Study in the Niger Delta Region,” by Gustavo C.D. Estrada, Jason Sali, and Patrizio Piras, Eni, et al. The paper has not been peer reviewed.

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Mangroves have gained attention as a carbon offset option because of their high carbon-storage capacity and diverse social and environmental benefits. Carbon stock in mangroves is approximately four times higher than in terrestrial forests and contributes to almost 10% of the global terrestrial carbon pool. In 2017, the Nigerian Agip Oil Company (NAOC) launched an initiative to restore mangroves to promote social and biodiversity benefits while contributing to offsetting its greenhouse-gas (GHG) emissions. The complete paper details the methodology and results of this initiative.

Introduction
Mangroves are coastal ecosystems mainly composed of typical tree and shrub plant species possessing adaptations to unstable, low-oxygen soil; high-salinity water; and frequent submersion. Fauna equally adapted to the unique environmental conditions observed in the mangroves also are considered part of the ecosystem.
Mangrove forests are recognized globally to be of extreme ecological, economic, social, and cultural importance because of the variety of goods and services they provide. Some of these include the protection of the coastline from the energy of the winds and waves and conservation of fishing and biodiversity in coastal and adjacent estuarine waters.
The literature suggests that more than 812,000 ha of mangrove areas, spread over 106 countries or territories, show potential for restoration. Furthermore, mangroves have been lost globally at a rate of 1–2%/year, which may account for an annual emission of approximately 0.09–0.45 GtCO2eq/year that could be avoided through conservation.
Because the dispersion of mangroves propagules (seeds that have germinated while attached to the mother plant) is driven by ocean and estuarine currents, natural recolonization can occur and mangroves recover successfully by secondary succession during a period of 10–15 years if conditions are ideal. However, ecosystem function may take more than a century to be fully reinstated. Understanding the autoecology, hydrological patterns, and factors impairing natural regeneration is key for a successful restoration project. Several examples exist of restoration programs that were unsuccessful for, among other problems, having failed to acquire these key prerestoration data.
During the last 10–15 years, a community-based ecological mangrove restoration effort has emerged based on the recognition that ecological science is not enough to assure successful restoration of mangroves and that social and economic issues must also be integrated.
Technology Focus: Formation Evaluation (August 2023)
Authors: Chen Zhiming 
Published: August 2023

Fractures, whether natural or hydraulic, serve as crucial pathways for fluid flow within rock formations. Because natural and hydraulic fractures are generated hundreds of meters underground, their parameters always seem to be a black box. Their influence on pressure propagation and well productivity, however, cannot be overstated. So how well are we doing in fracture evaluation and modeling?
Fracture evaluation can be regarded as an inverse problem, wherein the structural characteristics of a system are deduced based on input and output signals. Our objective is to ascertain the distribution, orientation, connectivity, and properties of fractures through the mathematical and physical methods applied to field data. Generally, we can use fracture-evaluation techniques such as surface tilt fracture mapping, downhole tilt fracture mapping, microseismic fracture mapping, tracer testing, temperature logs, production logs, borehole image logs, downhole video, caliper logs, production analysis, and well testing.
In parallel to fracture evaluation, fracture modeling assumes a computational approach to simulate fractures within subsurface reservoirs. We have various methodologies such as analytical, semianalytical, or numerical approaches to develop fracture models, including dual-porosity models, discrete fracture models, embedded discrete fracture models, and flow-net models. By means of fracture simulations, we can glean valuable insights pertaining to transient pressure behaviors, optimal production schemes, and estimation of ultimate recovery.
Despite the significant progress made, a gap still exists between theoretical advancements and practical field application in fracture evaluation and modeling, because underground fractures are often more complex than initially expected and nonunique solutions for fracture evaluation are commonplace. Thus, fracture evaluation and modeling represent complex and interdisciplinary fields, requiring expertise in geology, reservoir engineering, geomechanics, simulation, and related disciplines. We also need continuous research endeavors and advancements in fracture evaluation and modeling techniques to augment our understanding of fracture behavior and reservoir performance in the oil and gas industry, as demonstrated in the selected papers and recommended additional reading.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 212296 A Simple Analytical Model for Oil Production From Partially Fractured Reservoirs To Estimate Size of Finite Fracture Networks by Sait I. Ozkaya, Consultant
SPE 209624 A Flow-Net-Based Method for History Matching and Production Prediction of Shale or Tight Reservoirs With Fracturing Treatment by Hui Zhao, Yangtze University, et al.
SPE 209293 A Hybrid Embedded Discrete Fracture Model and Dual-Porosity, Dual-Permeability Work Flow for Hierarchical Treatment of Fractures in Practical Field Studies by Mun-Hong Hui, Chevron, et al.
Subsea Injection Systems Enable Carbon Capture and Sequestration
Authors: Carpenter Chris 
Published: August 2023

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32460, “Subsea CO2 Injection Systems for CCS Applications: Themes, Challenges, and Opportunities,” by Julian P. Tucker and Kamaldip Randhawa, Baker Hughes. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. Reproduced by permission.

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The complete paper presents a discussion of challenges and opportunities relating to subsea system design for CO2 injection in carbon capture and storage (CCS) applications. The scope of the text includes field development considerations, systems operation and control, intervention, monitoring, and barrier testing. A global review of existing and planned CCS developments is used to identify common system characteristics and core functional requirements. The paper reviews topics associated with CO2 transportation, injection, and storage across multiple disciplines to provide holistic guidance and commentary specifically for subsea system design relating to CO2 injection for CCS applications.

Value Drivers
For widespread adoption of CCS, dedicated geologic carbon storage (GCS) must be a commercially viable activity. Simply put, the cost of storage per tonne of CO2 must be less than the price that can be charged for storage as a service.
Financial incentives also must be present to support the carbon price for development to take place. Transitional incentives to close the gap between costs and the low value of CO2 emissions reduction also may be required to support development.
In all cases, however, the common denominator is that the cost of storage per tonne must be as low as possible. This is driven by the capital expenditure and operating costs of a project (as well as post-injection-period obligations), which include the cost of CO2 transportation and injection systems and associated equipment.

Types of Transportation and Storage Networks
For dedicated GCS, several types of offshore storage systems are available that are linked to different types of emitters, transportation networks, and value chains.
Storage systems linked to natural gas processing facilities may be considered single-point emitters. The overall architecture of these systems, however, will depend on where the CO2-rich production stream is processed and separated before reinjection.
The most common method of CO2 transportation to offshore locations is through a subsea pipeline, which enables a continuous flow of CO2 and a high system availability. It is worth mentioning that some developments also have considered transportation to offshore storage sites by ship, with injection through an intermediate floating storage vessel. Once installed, a pipeline provides continuous injection with high availability, whereas a vessel will be affected by transit time, weather conditions, downtime caused by maintenance, and high operating costs owing to fuel use. Furthermore, challenges with field expansion also may result.
Hybrid Power-Generation Concept Incorporates Offshore Wind
Authors: Carpenter Chris 
Published: August 2023

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 204901, “Hybrid Offshore Power Generation,” by Izleena Md. Iqbar, SPE, Fauzi O.B. Othman, and Hasmi Taib, Petronas, et al. The paper has not been peer reviewed.

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The operator has developed an offshore hybrid power-generation concept to leverage and optimize wind-turbine systems for power generation in weak-wind areas such as Malaysia. In this concept, one gas-turbine generator is replaced by an offshore wind turbine adapted to low wind speeds. This lowers maintenance costs and carbon exposure. Additionally, the fuel gas will be diverted to sales gas, thereby improving economics and making offshore renewable power generation feasible for oil and gas platforms.

Background
Malaysia is situated in a weak-wind area. Most of the operator’s oil and gas platforms are in water depths of more than 60 m, which are considered deep water for offshore wind-turbine systems. Offshore wind-turbine systems generally are expensive and not cost-effective for low-wind-speed areas where the annual average wind speed at hub height is less than 6.5 m/s. For economic reasons, offshore wind turbines are multimegawatt turbines designed for sites of International Electrotechnical Commission Class I or II only. However, a need exists to install CO2-effective, renewable electrical generators with high power density to support industrial plants that cannot follow the wind but are bound to local offshore oil and gas resources.
In view of these challenges, specific criteria have been identified for this project, namely specific rated power, maintenance costs, risk of hazards, capability of a black start (the ability of generation to recover from a blackout), and offshore capability.

Hybrid Offshore Power-Generation Project
From preliminary studies, it was concluded that a reasonable value for specific power is less than 200 W/m² to achieve high-capacity factors in a weak-wind region. The need for low maintenance costs calls for a solution with little technical complexity and a minimum of components. Capability for a black start in an island situation requires storage and parameters for the generator or invertor system of the wind power plant. At the time of writing, no wind turbine can be bought off the shelf for the purposes mentioned. A wind turbine found closest to these criteria is provided by a European manufacturer based in Estonia.
The offshore wind-turbine system consists of a customized wind turbine adapted to harness the energy from the weak-wind area and a microgrid system to integrate the wind turbine with the turbine generators, which are housed on a tension-leg-platform (TLP) floating structure. This floating platform is held by a gravity anchor.