bluuebunny/crossref_metadata_2025_split huggingface dataset:
Elephant Hunt: The Search for the Oil and Gas Supplies to 2050
Authors: Presley Jennifer 
Published: October 2023

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The oil and gas industry is at a critical juncture in the evolving global energy landscape. As the world intensifies its focus on combating climate change and embracing renewable energy sources, traditional fossil fuel exploration faces unprecedented challenges. The energy transition is now a tangible reality, reshaping the foundations of the oil and gas sector.
However, just as there is no shortage of proclamations that the end draws near for King Fossil’s reign at the top of the energy resource pyramid, an equally high number sees the old king hanging around beyond 2050. This back-and-forth between renewable and fossil energy proponents gives all a good bone of contention to gnaw on.
In September, Fatih Birol, executive director of the International Energy Agency (IEA), wrote in the Financial Times that it is taboo to suggest that demand for fossil fuels could go into permanent decline. He announced that the relentless age of growth for fossil fuels is set to decline by 2030, according to new projections by the IEA set to be released this month in its World Energy Outlook.
OPEC criticized the announcement, describing the narrative as “extremely risky and impractical to dismiss fossil fuels or to suggest that they are at the beginning of their end.” The oil-producing nations group said the IEA’s thinking on fossil fuels is ideologically driven rather than fact-based, and predictions like these are “dangerous” because they are often accompanied by calls to stop investing in new oil and gas projects.

Upstream Investment: Too Little or Just Right?
The IEA and OPEC did find a small patch of common ground, agreeing that there would still be demand for oil and gas in 2050 and that continued investment in new oil and gas projects is needed.
The underinvestment in upstream asset development has been a concern for several years, with the COVID-19 pandemic only exacerbating the issue, and according to a recent report by Goldman Sachs, oil and gas activity declined at a compounded 7% from 2014 to 2021. The investment bank expects primary energy capital expenditure to grow 48% by 2027 to $1.9 trillion, up from $1.3 trillion in 2022.
“We believe the energy industry has been underinvesting since the peak of 2014, with investments in traditional energy (upstream oil and gas) falling 50% in 2020 from the peak and driving an 18% reduction in global primary energy investments, from $1.3 trillion in 2014 to $1.0 trillion in 2020,” the bank said.
“A number of oil and gas investment decisions had been delayed since 2014, translating into 10 million B/D of lost oil production by 2024–2025—equivalent to Saudi Arabia’s annual production—and 3 million BOED of lost LNG production—more than Qatar, on our estimates,” according to Goldman Sachs.
Is Produced Water Really Water?
Authors: Rassenfoss Stephen 
Published: October 2023

Is produced water flowing out of an oil/water separator actually water?
Before answering, consider the fact that this question has set off a high-stakes legal battle over who owns produced water—landowners or oil companies—which is likely to end up before the Texas Supreme Court.
An appeals court ruling recently confirmed the oil industry’s control over produced water. The majority opinion supporting that decision said this noxious fluid is distinctly different from the groundwater that Texas law says is controlled by landowners.
However, one member of the three-judge panel dissented, saying that however chemically complex produced water is, it is not on the list of hydrocarbons covered by the oil lease.
The fact that anyone is fighting to own produced water, and the potential environmental and health liabilities that come with it, is a sign of how unconventional exploration and production has changed the Texas oil business.
“Questions about whether landowners owning produced water were sort of meaningless not that long ago because produced water was nothing more than waste,” said Stephen A. Cooney, a real estate attorney who closely follows developments in oil and gas law. He is one of several attorneys who has written online about the case that multiple lawyers say has “huge implications.”
The suit was originally filed in Pecos, Texas, which is the home of most of the people who live in Reeves County where the local facts of life help explain how produced water has become something worth fighting over.
The top tourist attraction in the area is the Balmorhea State Park which features a large “spring-fed swimming pool.” It’s an oasis of clear, cool water where only 0.3% of the 2,642-square-mile county is covered with water, according to the US Census Bureau.
Pressure to conserve fresh water has made fracturing with produced water increasingly the norm in the Permian Basin. Water reuse has spawned a growing network of produced water pipelines, water processing facilities, and injection wells to provide the millions of gallons needed for fracturing and disposal of the rest.
Reeves County is also in the heart of the Delaware Basin, where wells typically produce four times as much water as oil early on, and that ratio rises quickly as oil production plummets.
Reusing produced water reduces the amount of water that the operator must dispose in injection wells and provides a relatively cheap source of frac water.
And, most importantly, Reeves County is where two major landowners agreed to do something nobody had ever done before: sign a produced water lease. The contract gave Cactus Water Services ownership of what lawyers refer to as the “produced water estate.”
Case Study: A Novel Approach to Tankless Zero-Emission Crude Oil Production Facilities
Authors: Pittenger Tyler , Maltese Anthony , Palaia Joseph 
Published: October 2023

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The Environmental Protection Agency (EPA) and numerous states are introducing new emissions regulations which impact oil and gas producers. Additionally, under the pressure of stakeholders, the producers are committing themselves to decarbonize their operations. A large portion of these emissions occur at oilfield production sites. To eliminate these emissions, Pioneer Energy created a new type of skid‑mounted production facility. The technology was deployed on a pad in Weld County, Colorado, and demonstrated elimination of emissions, improved operational efficiency, and an increased crude yield of 11.3%. If adopted by the industry, this solution can dramatically reduce the emissions and carbon footprint of oil production.

The Challenge
There are five populated areas in the US that the EPA currently designates as Severe Ozone Nonattainment Zones. The Denver Metro and Front Range area, which also encompasses most of the Denver‑Julesburg (DJ) Basin, is one of these areas, and the EPA is currently working to include the Permian Basin as a sixth nonattainment zone. Oil and gas producers are actively seeking solutions to drill and produce wells while significantly reducing pad‑level emissions to achieve attainment. Strategies currently being employed include eliminating crude storage tanks, eliminating natural gas actuators, and consolidating processing from offset pads, each of which offer incremental improvements but do not address the whole problem. Current production facilities use passive means to separate the oil, gas, and water. This incomplete separation results in gas remaining in the crude, and when this gas leaves the crude, it results in fugitive emissions.

The Solution
To address this challenge, Pioneer Energy developed an active separation process called the Emission Control Treater (ECT) as seen in Fig. 1. The ECT receives wellhead fluid and uses a combination of heat and gravity in a closed‑ loop process to separate water, oil, and gas. The system sorts the hydrocarbons much more efficiently than traditional processes, resulting in crude which is completely stabilized, containing no flash gas. An additional benefit is that crude molecules that would be left in the gas instead remain in the crude, increasing its volume. By eliminating the flash gas, and through process electrification, pad emissions are eliminated. Pipeline-quality crude oil is output from the ECT and can be directed straight to the Lease Automatic Custody Transfer (LACT) unit or surge vessel if buffer capacity is needed for the crude midstream provider.
The ECT is emissions‑free when run on grid power, contains no gas-venting actuators, and replaces nearly all existing production facility equipment, including high-low pressure separators (HLPs), vapor recovery units (VRUs), gas busters, vapor recovery towers (VRTs), and storage tanks. It is capable of bulk processing and when assembled in parallel with multiple skids, the ECT system can accommodate a wide range of production profiles.
Machine-Learning Algorithms Optimize Drilling-Center Locations Offshore
Authors: Carpenter Chris 
Published: October 2023

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211772, “Optimizing Future Drilling-Center Locations Using Advanced Analytics and Machine-Learning Algorithms Offshore Abu Dhabi,” by Rail Salimov, Benoit Jaffres, and Jamal Alblooshi, ADNOC, et al. The paper has not been peer reviewed.

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Long-term development planning requires infill drilling. Because of the limited number of slots in the offshore environment, new drilling centers (wellhead towers) are required. Optimized location of drilling centers can play a major role in reducing drilling expenses. Two main challenges related to wellhead-tower placement are discussed in the complete paper: first, where to place future drilling centers based on subsurface coordinates and drilling constraints; and second, how to allocate dozens of subsurface targets to multiple drilling centers. The drilling-center placement optimization algorithm developed by the authors is based on multiple optimization parameters related to well cost.

Introduction
To finalize well trajectories, and thus best manage well costs, before the drilling phase, the following detailed analyses are required:
- Evaluation of horizontal trajectory in terms of landing point and total depth
- Optimization of horizontal drain length
- Optimization of the horizontal drain length in the best oil-bearing zone
- Torque-and-drag evaluation
- Anticollision assessment
- Selection of optimal completion accessories
However, for most giant offshore fields with complex plans, hundreds or even thousands of infill developments are required. Definition of optimal locations and allocations of wells to drilling centers will require multiple iterations of already tedious work. An alternative methodology is described in the complete paper that allows finalization of future facility placement with the use of open-source machine-programming tools and applied mathematics.
The presented methodology was deployed successfully on two major offshore fields where current production is connected through wellhead towers. Evolution of the development plan and the ramp-up of production means that additional drilling is planned during the next 10 years.
Approximately 100–150 development wells are planned to be drilled from yet-to-be-constructed wellhead towers. One of the main challenges in achieving cost efficiency is effective placement of the new towers to minimize the total drain length of all development wells.
The methodology covers the two most important aspects of facility construction that play vital roles in optimization of capital investment in facility expansions of offshore oil and gas fields. These aspects are optimized allocation of future wells to drilling centers and placement of those drilling centers.
Technology Focus: Artificial Lift (October 2023)
Authors: Romer Michael 
Published: October 2023

Buying a vehicle can be a daunting experience. Sometimes you wish you could refer to a guide of what has worked out well for users of certain models over time and under various operating conditions. Paper SPE 213059 does this by correlating past testing of downhole centrifugal separators and adding a machine-learning twist.
Once you’re about to make your selection at the car dealership, you may notice that the fine print states “mileage may vary” and wonder why that’s the case. Paper OTC 32398 explains how and why electrical submersible pumps (ESPs) are unable to perform as effectively when pumping viscous fluids by creating nondimensional models and validating them with field data. Paper SPE 214043 shows that frictional losses during plunger lifting can create a gap between actual and predicted performance.
Even if you succeed in making a no-regrets purchasing decision, the day may arrive when financial, operational, or reliability considerations encourage changing vehicles and perhaps downsizing. Paper SPE 213089 describes an artificial lift selection tool for unconventional reservoirs driven by reduced-physics models that can help identify when the time is right for change. Paper SPE 213975 extols the value of gas lift downsizing by optimizing the selection and placement of Venturi, orifice, and dummy valves to spur production uplift.
If you happen to have an emotional attachment to a vehicle, it can be difficult to let it go. But maybe you don’t have to; maybe you could repurpose that vehicle. Plenty of pump jacks in the history of the oil field have made use of truck transmissions instead of a standard gearbox. Paper SPE 214361 explains how ESPs could become electrical submersible generators to produce power in conjunction with injection or disposal operations.
Then again, it may just be easier and less stressful to look up some bus schedules.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 213059 Application of Machine Learning To Evaluate the Performances of Various Downhole Centrifugal Separator Types in Oil and Gas Production Systems by Laura Camila Osorio Ojeda, University of Oklahoma, et al.
OTC 32398 Relative Viscosity Model for Water-in-Oil Emulsion in Electrical Submersible Pumps: Comparing the ESP Head in a Real Scenario by Natan Augusto Vieira Bulgarelli, Unicamp, et al.
SPE 214043 A Mathematical Modeling of the Plunger Lift Considering Effects of Fluid Friction and Plunger Travel Velocity by Saurabh Rajvanshi, Oil and Natural Gas Corporation, et al.
Artificial Lift Timing and Selection Optimized With Reduced-Physics Models
Authors: Carpenter Chris 
Published: October 2023

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 213089, “Optimizing Artificial Lift Timing and Selection Using Reduced-Physics Models,” by Hardikkumar Zalavadia, SPE, Metin Gokdemir, and Utkarsh Sinha, SPE, Xecta Digital Labs, et al. The paper has not been peer reviewed.

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The complete paper presents an artificial lift timing and selection (ALTS) methodology based on a hybrid data-driven and physics-based work flow. The proposed method predicts future unconventional reservoir inflow performance relationship (IPR) consistently and allows for continuous evaluation of ALTS scenarios in unconventional reservoirs with multiple lift types and designs. Continuous use of this process has been shown to improve production, reduce deferred production, and extend the life of lift equipment.

Introduction
The intent of the work flow is to maximize the positive economic impact of a well. The authors write that, to their knowledge, incumbent methods do not include the effect of subsurface performance. In the proposed approach, feedback is injected to the reservoir and a closed-loop response is obtained implicitly because of the selection of artificial lift type and operational parameters of that type.
The hybrid reservoir modeling methodology is based on identifying transient well performance (TWP). The method is based on a novel formulation that combines diffusive time of flight (DTOF), succession of pseudosteady-state material balance, and transient productivity-index (PI) concepts for estimating dynamic reservoir deliverability. (Equations associated with these processes are provided in the complete paper.) This is combined with well-deliverability estimation for different artificial lift methods and their operating parameters to perform continuous nodal analysis and forecast phase rates using novel PI-based forecasting techniques.

TWP Analysis
This work establishes a practical method to estimate transient-well PI for every well at field scale to understand unconventional well performance. This transient PI then can be used in a variety of applications, including well forecasting, artificial lift planning, production optimization, and field development planning. The complete paper is focused primarily on using the TWP work flow for optimizing ALTS in unconventional reservoirs that is practical in its application at a field scale.
Fig. 1 depicts the suggested work flow, which combines reduced-physics and data-driven methodologies to describe well performance over a series of steps. For TWP calculations, material balance is used through a sequence of pseudosteady states on the drainage volume evolution of a closed system.
Study Explores Design, Potential of Electric Submersible Generators
Authors: Carpenter Chris 
Published: October 2023

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214361, “Electric Submersible Generators: Using ESPs in an Unfamiliar Way,” by Charles E. Collins, Kenneth J. Frazier, and Bryan Coates, SPE, Baker Hughes. The paper has not been peer reviewed.

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The electrical submersible generator (ESG) is a modern interpretation of an old idea. The ESG can generate electricity to meet surface power needs or feed directly into the grid to create a revenue stream under the proper injection conditions. In typical configurations, a standard centrifugal pump is used in combination with an induction motor operated in such a way for the mechanical work of the pump to be converted into electrical energy. The complete paper explores ESG design considerations, theoretical underpinnings, and potential applications.

What Is an ESG?
A generic geothermal power plant typically consists of production wells that can be either artesian or artificially lifted. The heated well fluid will transfer the heat to a working fluid that rotates turbines to generate electricity. The reservoir fluid eventually will be reinjected into the formation to be warmed again and reproduced. It is common to use conventional electrical submersible pump (ESP) equipment to produce the fluids from the formation.
The ESG concept focuses on injection wells from these power plants. Instead of drawing power from a source and moving fluid to the surface, the ESG takes injected fluid from the surface and creates power that can be used to offset surface power requirements onsite or sold directly back to the grid to generate revenue.
The components of the ESG are very similar to those of an ESP, with an intake, discharge, seal, and cable attached to the motor. However, many of the components act essentially in reverse. The motor becomes a generator as it is driven by the pump acting as a turbine. The conventional ESP discharge becomes the intake, and the intake becomes the discharge. The cable still transmits the energy from the motor to the surface and vice versa. The seal section isolates the generator from the well fluid, handles thrust from the turbine, and equalizes the external pressure of the well with the internal pressure of the system. The generator effectively acts as a brake for the turbine. While most ESP stages are not typically designed to operate as a turbine, many will still maintain a system efficiency expected of ESPs.

Application Guidelines
As with conventional ESP systems, proper application of this equipment ensures desired run life and optimal electrical generation. General steps of equipment selection include the following:
- Collect basic wellbore information
- Verify flow rate, temperature, and pressure of injected fluid
- Size the turbine accordingly based on the expected flow rate and pressure
- Determine the size of the generator based on the load from the turbine and the expected heat rise
Study Reviews Eagle Ford Parent-Well Frac-Hit Analysis, Prediction, and Mitigation
Authors: Carpenter Chris 
Published: October 2023

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3873139, “Eagle Ford Parent-Well Frac Hit (Frac-Driven Interaction), Impact Characterization, Prediction, and Mitigation,” by Yongshe Liu, Lucy Luo, and Susan Naiser, ConocoPhillips, et al. The paper has not been peer reviewed.

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While some wells show production uplifts after a frac hit (FH), many wells experience production degradation or complete loss of production because of failed casing or plugged wellbores. The complete paper focuses on Eagle Ford FH characterization, production-impact-prediction methods, and mitigation techniques. The techniques and findings presented in this paper are intended to improve the understanding of FH trends and their effects on the development of unconventional reservoirs.

FH Detection and Data Collection
Parent-Well Production Data. The authors write that identifying and building a database recording FH effects for every parent well has been a significant effort, with more than 1,600 wells drilled in the Eagle Ford by ConocoPhillips. This mass of data, however, serves as an excellent record of changes to production rate, water cut, yield, and pressures.
Parent-Well Surface Pressure. Parent-well surface pressure data can be important for FH analysis. Such data provide direct measurement of the timing and magnitude of FHs at the parent well. FH-event timing typically can be correlated with the pumping of a specific completion stage when integrated with evaluation of stress and expected fracture orientation. With this information, an FH pathway can be inferred between the infill and the parent wellbore. Collating this information assists in the generation of a map that captures all FH events with the extension of this analysis to all stages and parent wells.
To characterize FHs, parameters derived from the pressure response include the rate of pressure increase (intensity), pressure-increase magnitude, time to response, and volume to response. An automated tool has been created to identify these pressure-based parameters and record them in a database.
FH Diagnostic Data. FHs can be detected using special hydraulic fracture diagnostic data that are not collected commonly, such as microseismic, distributed acoustic sensing, downhole pressure gauge, and tracer data.
Other relevant information used for FH analysis includes well spatial configurations, completion data, reservoir properties, and operational data, such as mud-loss and cleanout data.

FH Analysis Work Flow
The proposed integrated work flow for analyzing FHs involves collecting data on fieldwide FH events and their associated production effects and incorporating other relevant information such as geology, completion, and well schedule. Empirical analysis is conducted to identify the key trends and drivers of FHs, followed by the development of mechanistic models for a better understanding of the underlying physics and a multivariate analysis (MVA) model for prediction.