bluuebunny/crossref_metadata_2025 huggingface dataset:
Guest Editorial: Are We Really Ready for Digital?
Authors: Borras Maria Claudia
Published: October 2023

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In my 30 years in the energy industry, I don’t think I’ve seen anything capture our collective imaginations quite as much as digital has—not only in our industry, but also in our personal lives.

We’re surprised—and often amazed—by the way digital has changed our lives with smart phones, streaming, and online connections. We’ve seen the medical industry transform patient well-being and retail supply chains become vibrant when they’re underpinned by strong digital tools.

Irrespective of what’s happening elsewhere, however, we must admit that the oil field is still in the early days of its digital journey. There are many reasons for our slow start, of course, and the intention of this editorial is not to belabor them; instead, I want to provide a good dose of pragmatism as we consider what’s next for digital in the oil field.

At this juncture in our journey, it’s time to give serious thought to the expectation-reality gap … the cultural differences between the way we’ve always done things in the oil field and the way that digital is changing us … and the pain points that may trip us up unless we’re careful.

Data, Digital, and Expectations

In oil and gas operations, we collect enormous amounts of data—and we should expect that this data contains insights to help us streamline operations; orchestrate activities across multiple stakeholders; deliver more efficient, consistent outcomes; and maximize recovery.

The challenge is that data doesn’t mean much by itself. I agree with mathematician Clive Humby, who referred to data as the “new oil.” Oil must be refined into products—such as gasoline or plastics—to create value. The same is true of data which, when refined, can be used to understand reservoir characteristics, calculate nonproductive time, and myriad other things.

But unlike oil, data is a renewable resource—which enables it to create additional value on new and different levels. We can use refined data to make decisions, refine it again to make different decisions, or even go back to the original data and reprocess it to gain new insights. We can apply data to models repeatedly as they evolve, improving clarity around particular challenges, or finding new ways to solve problems.

But, in the end, data is still only data. And that’s why we’re so focused on digital.

Digital gives us the tools to do something with the data.

There’s an interesting construct here. Just as data can’t do much by itself, digital is simply a box of tools—data analytics, visualization, the internet of things (IoT), machine learning, digital twins, cloud capabilities, and more. The relationship between data and digital is necessarily symbiotic—and we will do well to remember this when we set expectations for what digital can and cannot do.
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.
Technology Focus: Sand Management (October 2023)
Authors: Mahmoudi Mahdi
Published: October 2023

As drilling and completion activity resumes post-pandemic, the sand-control market faces several logistical challenges. Inflation and supply-chain interruption concerns are expected to continue into 2024 because of high volatility in raw material pricing amplified by geopolitical tensions in Europe and the South China Sea. As oil price strengthens, consumer preferences shift and more operators investigate newer technology and focus more on performance than price.

Despite these factors, the fundamentals of sand control and sand management remain the same. As more-challenging reservoirs are being developed and new difficulties arise, however, more engineers are questioning the conventional sand-control aperture-sizing wisdom.

Any sand-control effort aims to manage solids production while creating the fewest restrictions to fluid flow. To assure that sand-control efforts meet these goals throughout the life cycle of the wells, engineers must design them in a way that can withstand the forces of nature, doesn’t erode with high and localized flow, doesn’t corrode with the harshness of produced fluid, and doesn’t mechanically deform during installation and life-cycle loads. If you are interested in diving into these design processes, paper IPTC 21158 provides insight.

With the higher adaptation of flow-control devices in recent years to improve flow segmentation and reduce the premature failure of sand control because of highly localized flow, flow-control-device implementation is becoming an integral part of sand-management strategy. More papers every year discuss the design process and field implementation of various kinds of flow-control devices along with sand controls. Paper SPE 210299 provides good insight into some of the field challenges and results of implementing flow-control devices with sand control. As always, monitoring for sand and solid production is key in any sand-management effort to assure the integrity of the system and maintain the containment of the fluids. In the past year, several papers focused on monitoring, including discussions of new technologies and presentations of field case studies. Paper IPTC 22989 is among the interesting papers in this subject.

Recommended additional reading at OnePetro: www.onepetro.org.

IPTC 21223 Lesson Learned From First Application of Openhole Standalone Screen With Autonomous Inflow Control Devices in Oil Field Offshore East Malaysia by Catherine Ye Tang, Petronas, et al.

SPE 210128 Erosion-Resistant Sand Screen: Development and Deployment by Antonio Lazo, Chevron, et al.

SPE 208162 Prediction of Threshold Sand Rates From Acoustic Monitors Using Artificial Intelligence by Ronald E. Vieira, University of Tulsa, et al.
Plasma-Sprayed Coatings Resist Erosion in Wire-Wrapped Screens
Authors: Carpenter Chris
Published: October 2023

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21158, “Development of Plasma-Sprayed Coatings To Improve the Erosion Resistance of Wire-Wrapped Screens,” by Lukas Ochmann, SPE, and Mohd M. Amro, SPE, TU Bergakademie Freiberg, and Bernd Gronde, Fraunhofer IKTS Hermsdorf, et al. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission.

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A newly developed coating is put on the outside (i.e., facing the formation) of standard wire-wrapped screens to make the slots erosion-resistant. The coating consists of ceramic or hard metal and is applied by plasma spraying. An extensive development and verification program was conducted to guarantee defined slot widths, corrosion resistance, and mechanical strength of coating and screen. The coating improves resistance against erosion, can withstand corrosive well environments, and features mechanical properties suitable to be safely installed in any well.

Thermal Spraying and Composition of Coatings

The screens are coated using thermal spraying. This process uses a hot plasma jet to melt powdery materials and apply them to a solid surface. The molten particles solidify on the surface and form a hard coating with little porosity. No chemical reaction exists between the base material and the coating.

Several different steps are necessary to coat a wire-wrapped screen. First, the screen is sandblasted in a distinct way to provide a defined surface roughness. After that, a thin bonding layer is applied by thermal spraying. This intermediate layer further improves the adhesion of the functional layer. This erosion-resistant main layer, which consists of hard metal or ceramic, is applied next by thermal spraying. The coating is finished by filling up the pores of the sprayed layers with a liquid sealer.

The coating changes the geometry of the slots, slightly reducing the slot size and creating a less-sharp slot opening. By adjustment of the process parameters of the thermal spraying and choice of the correct initial slot width, defined and constant slot widths can be produced for the final product.

Corrosion Investigation

All samples and future prototypes are based on 1.4404 (316L) stainless steel. Combinations of four bonding layers, six functional layers, and five sealers were investigated. In total, 237 different samples were corroded under different conditions. The samples were submerged halfway into the brine so that the effect of the three-phase interface (brine, gas, and sample) could be investigated over a period of multiple weeks (minimum 3 weeks, maximum 18 weeks) at 60°C. Further experiments were conducted with nitrogen and hydrogen atmospheres for 3 weeks. The first tests were conducted with samples made from wire-wrapped screens. A second batch of tests was performed with coupons for tensile bond tests.
Reduction of NORM Waste in the Oil and Gas Industry with Indirect Heated Vacuum Distillation Technology
Authors: Borbet J. , Veciana J. , Stiels C. , Schmidt R.
Published: October 2023

One of the most pressing challenges currently in the oil and gas industry is the management of natural occurring radioactive material (NORM) or technologically enhanced NORM (TENORM) containing wastes. The exploration and extraction operations of oil and gas are frequently executed in subsurface formations that contain natural radionuclides such as 226Ra, 228Ra, 222Rn, 210Pb, 40K etc. The natural radioactivity present in the oil and gas extraction sites can be significantly enhanced (>10,000 Bq kg−1) due to technological and human activities creating TENORM waste. TENORM is caused by the concentration and accumulation of natural occurring radionuclides in the internal surfaces of equipment, producing wastes such as scale and sludge formations in pipes. In addition, NORM is concentrated in the produced by-products from oil extraction such as water. Radionuclides present in oily wastes often form complex compounds leading to different forms of sedimentation such as sulfates, silicates, carbonates, and in several cases, mercury is also a major contaminant found. This mixture of contaminants poses challenges for transport, treatment, and safe final disposal. As a result, currently there are limited NORM waste management solutions apart from temporary storage facilities.

In 2022 at the International Conference on Management of NORM in Industry, one of the main challenges in the oil and gas industry was reported as the lack of waste disposal options in several countries. With increasing NORM waste quantities several consequences may arise such as space limitations in disposal sites and increasing operational costs. Volume reduction techniques such as gravitational separation, extraction and enzyme pre-treatment, in-situ flocculation, physical separation, and chemical treatment, etc. have been also applied to NORM to reduce the costs associated with the disposal of the waste. Disposal techniques involving deep well injection such as slurry fracture injection, sub-fracture injection or cavern well injection have been investigated and applied in several countries. However, injection techniques have several limitations such as the requirement of a distinct geological formation, the potential risks associated with leaks or earthquakes, and the difficulty to inject slurries and pasty materials because it can clog the wells.
Multi-Seismic Attribute Interpretation and Machine Learning Based Analysis to Unlock Development of Stratigraphically Complex Secondary Reservoir Potential
Authors: García S. Mata , Carrillat A. , Torres W. , Cisneros P. , Lucas A. , Miller C. , Garrido J. , Rodas J. , Zamora P. , Karelis J.
Published: October 2023

This case study in the Oriente Basin demonstrates how integrated and weighted seismic post-stack and pre-stack attributes enable identification of upside potential as well as de-risking of well planning and execution in reservoirs with complex stratigraphic architecture within a mature oil field. This approach analyzes the usability of Machine Learning (ML) algorithms to drastically improve the spatial estimation of rock properties related to oil bearing reservoir sandstones. Multiple seismic attributes interpretation by Artificial Neural Networks (ANN) is a robust approach to map thin sandstone reservoir layers embedded in contrasting lithologies and allows for improved predictability in new well locations. Multiple attributes are generated, in overlapping windows to address interference associated with the thin sandstone layers, then analyzed, selected, ranked, and combined by ANN. Seismic amplitude interpretation is run in parallel with other processes to reduce subsurface risk, including seismic pre-stack inversion, spectral decomposition, and waveform classification.

In 2021, a new stage of field development was initiated, targeting secondary reservoirs in the Cretaceous Napo Formation with low recovery factors. These reservoirs are characterized by rapid lateral and vertical stratigraphic variations, deposited in a tidal fluvio-estuarine environment. The multi-attribute workflow was implemented to identify sweet spot areas, assess potential and optimize well locations and designs. The execution of this new field development strategy was first deployed in a selected drilling pad, previously identified as the best candidate for secondary reservoir development. This pad includes 4 horizontal and 2 deviated producers, and 5 workovers (WOs). The allocated production in the area and reservoir increased 8 times from the baseline oil production rate due to this recent activity. This marked the first horizontal well targeting T Superior sandstones in the Napo Formation in the entire Oriente Basin. In addition, a waterflooding project and surveillance was implemented to maintain average reservoir pressure, balance patterns to maximize oil production, and minimize the possibility of early breakthrough and high-water cuts in producers. Multi-domain analysis with seismic attributes is used for optimization of well planning and well placement, assessing future opportunities, and understanding reservoir continuity for waterflooding. This workflow established a new standard to enable high-grading secondary reservoirs potential and optimize future development plans.
Prediction and Analysis of Liquid Carrying by Plunger Gas Lift in Wellbore
Authors: Xiong Shuquan , Zhang Binbin , Liu Ping , Zhao Wei , Li Yongfeng , Zhang Jianbo , Sui Xiuan , Fu Weiqi
Published: October 2023

Plunger gas lift is a good method to drain the accumulated water in the wellbore. In this work, a dynamic model is established to predict the liquid carrying process by plunger. A case study is carried out to investigate the applicability of the proposed model, and the law of liquid carrying by plunger is analyzed. Three stages exist during the movement process of plunger, that is, the accelerated ascent stage, decelerated ascent stage and drainage stage. The decelerated ascent stage has the longest duration, and the velocity increases significantly with time as the liquid level reaches the wellhead during the drainage stage. As the well depth increases, the variation magnitude of the plunger velocity during the accelerated ascent stage and decelerated ascent stage decrease, and the duration during the decelerated ascent stage increases. As the initial height of water column increases, the velocity of the plunger decreases at each stage, and the decrease magnitude becomes less obvious. As the inner diameter of the tubing decreases, the speed of the plunger gradually decreases at each stage. Among the three influencing factors, the height of initial water column has the greatest impact on the efficiency of liquid carrying by plunger.
Bhagyam Field: Peripheral Waterflood to Full Field Polymer Flood. Subsurface, Reservoir Management & Field Development Learnings from 10-Year-Old Field Journey
Authors: Kumar V. , Garg H. , Lodha V. , Biswas N. , Das J. , Mishra S. , Kumar M. S.
Published: October 2023

Bhagyam field is a moderately viscous onshore oilfield in the Barmer basin located in the western part of Rajasthan state in India. The main producing unit is Fatehgarh comprising of multi storied fluvial sandstones. Fatehgarh is an excellent reservoir with multi-Darcy permeability. The field was discovered in 2004 & has been in production since Jan-2012. A total of 200+ wells have been drilled in this field since the start of field development journey. The field has been on peripheral hot water flood since the start of production. A polymer flood pilot was done in the field in 2016 & based on the success of the pilot, full field polymer injection supported by peripheral water injection was commenced in Oct-2020.

The paper captures the developmental journey of the field; challenges observed in the field during its production life, surprises encountered during waterflood phase & initial few years of polymer flooding phase and subsurface & modeling challenges encountered in the field. During the initial waterflooding phase, water breakthrough & the rise in water cut in the field was faster than expected. The then subsurface models were unable to capture early water breakthrough and fast water cut rise. The reservoir modeling philosophy in the field had to be revamped with updated understanding of the field to better capture field performance. Also, the field has a bio-degraded oil zone with relatively higher oil viscosity where a major part of the in-place volume is present. Commercial exploitation of the bio-degraded zone has posed its own challenges. The journey of polymer flood in the field has been a success story. The field has performed as expected but challenges in terms of injectivity, conformance, surface issues etc. have been observed.

The paper discusses the learnings from the first few years of field production life when field performance deviated from expectations and the reasons for that deviation. The paper also summarizes how subsurface & reservoir management learnings from the initial field life were incorporated while planning polymer flooding in the field. The paper also discusses learnings from subsurface & operational challenges encountered during the initial few years of polymer injection in the field. The paper also summarizes how subsurface modelling has evolved in the field over time to better capture field performance.

The understanding of reservoir characteristics, rock-fluid interaction & fluid movement in Bhagyam field has improved significantly in the last 10 years and this has led to improved reservoir management practices & better development planning of the field resulting in reserves addition & recovery factor improvement. The learnings from this field can be applied to similar reservoirs across the world.
Undiscovered Potential in North Oman's Subtle Natih Truncation Traps
Authors: Butler Emma , Shukaili Bushra Al
Published: October 2023

The Cretaceous age Natih truncation play in northern Oman is an underexplored play due to the challenges of finding subtle traps. Key elements include two angular unconformities occurring in north Oman that contribute to the complexities of the truncation trap. The Turonian unconformity subcrops the Wasia Group under the overlying Fiqa shale of the Aruma Group. The Base Cenozoic unconformity not only erodes the Aruma, but also the Wasia Group at a higher angle than the Turonian unconformity. Both groups truncate roughly toward the west/southwest, and the area with the most Natih truncation potential is the area in which Natih is overlain by the Cenozoic. As the two unconformities merge, seismic multiples from the younger Hadhramaut Group distort the seismic imaging of the unconformities due to the absent Aruma Group. Lastly, variations in the Natih facies also cause complexity due to differing impedance contrasts between the lower Hadhramaut and the upper Wasia Group. For proper lead identification, the difficulties in the seismic imaging, seismic interpretation, and well top interpretation need to be accounted for and addressed.

The simplest and most cost-effective way to tackle this problem was to use the most current seismic volume to create a variety of filtered volumes and angle stacks. These volumes were used to understand which reflectors could be considered robust and which are influenced by multiples. Depending on the area, the deeper Natih reflectors were determined to be the most representative of the Natih trend. In areas of more truncation, the deeper Shuaiba formation reflector was a more suitable guide. An extensive study of the well tops in areas with dense well penetrations was conducted to understand the thickness variations and ranges between the individual Natih units’ reservoir-seal pairs. These thicknesses were integrated with the seismic data to create the geologic model and quantify the uncertainty. The final model represents a series of high-resolution reservoir-seal pairs and their expected areas of truncation.

The result of this project was a detailed model incorporating well tops, seismic horizon and fault interpretations, and isopach guidance. This model was used to identify where reservoirs are truncating against the top seal, how quickly the reservoir gains thickness away from the truncation, the thickness of the base/lateral seal, and probable juxtapositions across faults. The information gained can then be used to prioritize areas with more truncation potential.

Bypassed Natih pay in previous penetrations can now be attributed to a truncation trap. And more importantly, new prospects can be matured with larger prospective areas and volumes due to the understanding of the stratigraphic trapping mechanism. As of 2023, several new truncation trap fields have been discovered, and many more prospects await testing. This modeling technique can be applied to similar truncation opportunities locally and worldwide.
Reducing Water Saturation Uncertainties in a Low Resistivity Pay Carbonate Reservoir
Authors: Bankole I. O. , Nachiappan R. , Pramudyo Y. B. , Reddy R. , Al Marzouqi K. I. , Alsalami M. , Alzeyoudi M. , Ojha A. , Fathalla M.F , Baslaib M. A. , Amer M.
Published: October 2023

Water saturation is a key input in the determination of hydrocarbon resource estimations among many other uses. Evaluating water saturation is a huge challenge in heterogenous carbonate because of its diverse pore types. In order to find suitable evaluation techniques, a proper identification of the source and the characterization of these reservoirs is essentially required. There are several known causes of the low resistivity pay phenomenon namely: micro-porosity, fractures, paramagnetic minerals, and deep conductive borehole mud invasion. In Carbonates main cause is the presence of micritic pores or microporosity which strongly suppress or mask resistivity log response making water saturation evaluated from this type of reservoir rock inaccurate or over-estimated using the Archie equation. To compute a more accurate and realistic water saturation from such reservoir requires, an alternative resistivity independent approach is required to reduce the uncertainty in water saturation estimations.

This paper demonstrated a simple alternative and pragmatic approach in evaluation of water saturation in complex carbonate reservoir with varying presence of micro porosity formed from micritization. The approach an integrated workflow based on geological(lithofacies/diagenesis) and petrophysical rock typing with other petrophysical methods to build a realistic saturation model in this challenging environment.

The integration of various subsurface and dynamic data has contributed significantly to identification of the source of LRP, the distribution and the impact on the water saturation in oil and gas zones of the reservoir. Thus, reducing uncertainty, improving the reservoir characterization and HCIIP significantly most especially in the oil zone where LRP effect is more pronounced.