bluuebunny/crossref_metadata_2025 huggingface dataset:
Modernizing Data Management by Developing a Data Mesh Knowledge Layer with OSDU
Authors: van der Haven Michaël , Thakur Vijender
Published: October 2023

Data Mesh is a concept that is utilized as a way forward to start connecting various data sources and making their content available as data products to end-users. In organizations embarking on a digitalization journey, it is an attractive approach to prevent having to migrate all, or part of the landscape into a new solution or platform. Especially in organizations that already have a well-established and historically grown but complex data landscape.

As with any other industry, digitization is a must for organizations to unlock existing data and create new innovative solutions, for example with the help of AI. Examples are the creation of new data products, becoming more efficient and safer in their operations and above all contribute to energy security in our world.

With respect to new data solutions, the OSDU standard has become one of the defacto standards to make data available for users active in the subsurface and wells space. While it is often presented as either a platform to migrate data to or incorporate it as a digitized data lake for the organization, we would like to present OSDU as part of a Data Mesh.

In practice, data lake solutions, especially relatively complex to operate solutions like OSDU, are seen as too complex for the smaller to mid-size operators that have the same data challenges and need for digitization as the larger operators. A migration or data lake integration project is often too disruptive for such organizations. But also, for larger operators that have a need for a day-to-day continuation of their operation with solution support, can benefit from using a Data Mesh approach.

In our solution we present OSDU as the ‘knowledge layer’ in a Data Mesh. This means that the strengths of OSDU on the management of meta-data and its open architecture are utilized to create a System of Engagement for any user in an organization, without being disruptive to the day-to-day operations and use of existing solutions.

To create a Data Mesh with OSDU, the solution needs to be enhanced on the levels of Search, Governance and Data Product generation. These enhancements are beneficial to OSDU in general, with or without being in in a Data Mesh, but become even more powerful when applied in an enterprise-wide solution.
A New Paradigm for Automatic Well Path Generation Using Multidisciplinary Constraints
Authors: Cayeux E. , Pelfrene G. , Mihai R. , Dvergsnes E. , Tjøstheim B. P. , Baume A. , Khosravanian R. , Kristiansen T. G.
Published: October 2023

The well planning process involves many disciplines. Due to the multidisciplinary nature of the process, many iterations are necessary to generate a well path. This is a time-consuming process that finally leads to chosen planned trajectories that may be sub-optimal. It is proposed to radically revise the well path generation process to reach the vision of planning a well in one day with high quality.

Departing from the traditional incremental approach to well path generation, the proposed method relies on the collection of experienced-based constraints from each discipline to generate possible alternatives to the well path. A fundamental difference with the classical well path generation process, which works with one or a handful of planned trajectories, is that an ensemble of possible well paths is generated through the proposed method. If the constraints are loose, many planned trajectories might be generated but if the constraints are tight, there may be very few or possibly no solutions. As a result of this new work process, the multidisciplinary team can focus on the relevance of the constraints rather than on the details of the planned trajectory. Capturing these constraints is the fundamental result of the well planning process; the ensemble of possible well paths being only a byproduct of it.

The novel method comes with a set of concepts that provide subject matter experts with greater leeway for defining the well path generation problem in a generic way. These concepts have been designed to seamlessly allow for any subsequent updates of the well plan, whether for the target or group of targets and their associated wellbores, the wellbore architecture and its relation to geo-pressure margins, or the surveying program with regards to wellbore position uncertainty. Whenever possible, characteristics attached to these concepts are described implicitly to cope with mutual interactions between constraints. An extensible classification of the constraints is provided and illustrated with examples commonly used to define drilling programs. As a result of the propagation of user-chosen constraints, complex problems such as finding well paths that respect anti-collision criteria, avoid faults or cross them with a high incidence angle if unavoidable, and satisfy inclination limits to cross certain formation layers are solved completely automatically.

Innovation does not come for free: the new paradigm presented in this paper induces a significant transformation of the well planning process. However, the versatility of the approach should largely compensate for the expected change in end-users’ habits both by a faster delivery time of every well plan (or even large-scale field development) and by allowing a seamless update of the latter when drilling operations demand it.
Polymer-Assisted-Water-Alternating-Gas for Improving the CO2 Flow Properties in Porous Media
Authors: Yegane Mohsen Mirzaie , van Wieren Thijs , Fadili Ali , van Batenburg Diederik , Leblanc Thierry , Zitha Pacelli
Published: October 2023

CO2 flow in porous media is vital for both enhanced oil recovery and underground carbon storage. For improving CO2 mobility control and thus improved reservoir sweep efficiency, Water-Alternating-Gas (WAG) injection has often been applied. The effectiveness of WAG diminishes, however, due to the presence of micro-scale reservoir heterogeneity which results in an early breakthrough of gas. We propose Polymer-assisted WAG (PA-WAG) as an alternative method to reduce gas mobility, while also reducing the mobility of the aqueous phase, and consequently improving the performance of WAG. In this method, high molecular weight water-soluble polymers are added to the water slug.

The goal of this work was to investigate the feasibility of PA-WAG and study the transport processes in porous media. An ATBS-based polymer (SAV 10 XV) was chosen as polymer and CO2 at immiscible conditions as gas. The objective of the experiments was to compare the performance of CO2, WAG, and PA-WAG injection schemes by conducting a series of X-ray computed tomography (CT)-aided core-flood experiments in Bentheimer cores.

Core-flood results clearly demonstrated the beneficial effects of PA-WAG over WAG and continuous CO2 injection. Continuous injection of CO2 led to the recovery factor (RF) of only 39.0 ± 0.5% of the original oil in place (OOIP). In-situ visualization of CO2 displacement showed strong gravity segregation and viscous fingering because of the contrast in the viscosities and densities of CO2 and oil. The injection of WAG almost doubled the oil recovery (i.e., RF=76.0 ± 0.5%); however, the water and gas breakthroughs still occurred in the early stage of the injection (0.22 PV for water and 0.27 PV for CO2). The addition of the polymer to the aqueous phase delayed both the water and CO2 breakthrough (0.51 PV for water and 0.35 PV for CO2). This resulted in an additional 10% in the recovery factor. Using a single injection method, polymer adsorption was found to be 79.0 ± 0.5 μg polymer/g rock. The polymer adsorption can reduce the micro-scale permeability and as a result, mitigates the gas channeling. This in turn leads to the delay in CO2 breakthrough during PA-WAG injection as was evident from in-situ visualization.

This experimental study demonstrated a positive response of PA-WAG compared to WAG and paves the way for its implementation in field applications.
Successful Deepwater MPD Application in Drilling and Cementing Through Depleted Formation with Wellbore Instability and Loss Circulation Challenge Offshore of Sabah
Authors: Benny B. , Tan J. , See J. , Foo J. , Othman F. , Mathew M.
Published: October 2023

Managed Pressure Drilling (MPD) has become the essential drilling technique to drill problematic zones in these past decades due to its ability to precisely manipulate downhole equivalent mud weight (EMW). This ability empowers the operator to save time and cost when drilling through loss zone with lower drilling fluid and at the same time, able to retain EMW above the wellbore instability or, if required, pore pressure gradient.

This paper describes the crucial role of MPD in a drilling operation on a horizontal deep water oil producer well in Sabah region, offshore of East Malaysia, to help the Operator recover from Wellbore Instability and Loss Circulation issues and successfully drill and cement the problematic section. The main challenge of the well is the tight drilling window between depleted sand formation and the interlayered shale formation. Therefore, the MPD Integrated Riser Joint (IRJ) was deployed along with the riser string prior drilling 12.25 in hole section. Initially, the section was drilled conventionally with wellbore strengthening techniques, only to encounter unmanageable static losses. After multiple unsuccessful attempts to cure losses, the section was cement plugged to sidetrack the well.

Considering the substantial challenges encountered, the well was sidetracked with lighter drilling fluid and applied surface back pressure (SBP) to maintain its bottom hole pressure above the wellbore instability gradient and below the fracture gradient. After the well had reached target depth, the drilling assembly was pulled out of hole in MPD mode without having to displace the well to heavier tripping mud and, once it was above the Subsea Blowout Preventor (SSBOP), the well was then isolated with blind shear rams (BSR). To continue maintaining SBP below the BSR, the MPD system was lined up on a surface loop circulation in such a way that the SBP was applied to the well via kill line. With the casing string delivered to the bottom, Managed Pressure Cementing (MPC) was utilized to cement the casing by having a schedule of SBP against pumped strokes that was formulated by software simulation to give a minimum pressure surge when the cement slurry entered the open hole.

In addition, the paper also describes the equipment setup required onboard a drillship for drilling with MPD in a deep-water setting. The MPD setup enables the application of advanced flow detection system and riser gas handling which are critical in drilling deep water wells. With all these features, MPD Deepwater application has successfully delivered the well to target depth which once was undrillable.
Pressure- and Rate-Transient Model for an Array of Interfering Fractured Horizontal Wells in Unconventional Reservoirs
Authors: Ozkan E.
Published: October 2023

An analytical solution is presented for pressure- and rate-transient behavior of an array of, parallel, fractured horizontal wells in an unconventional reservoir. Wells are of equal length but otherwise of unidentical properties. Each well has an arbitrary number of uniformly spaced identical, finite-conductivity fractures and is surrounded by a stimulated reservoir volume. Properties of hydraulic fractures and stimulated reservoir volumes may vary from well to well. Different properties may also be assigned to unstimulated reservoir section between wells. Natural fractures in the stimulated and unstimulated reservoir volumes are accounted for by the transient dual-porosity idealization. Flow domain is divided into blocks of one-dimensional flow under the trilinear flow assumption. Analytical solution for each block is obtained by the appropriate Green's function and coupled with the neighboring blocks by the continuity of pressure and flux at the block interfaces. Superposition principle is applied to consider variable production conditions as well as nonsynchronous production and shut-in schedules of wells. The final solution is in the form of a matrix-vector equation in the Laplace transform domain and inverted into time-domain numerically. Results are robust and reasonably accurate for most practical applications of single-phase oil and gas production from multiple wells in an unconventional reservoir. The solution provides an efficient tool to assess well interference effects for different well completion designs and varying reservoir characteristics. The speed of calculations is convenient for pressure-transient and production-data analysis, as well as for the initial calibration and verification of more complex numerical models. The closed analytical form of the solution enables assessment of flow regime diagnostics under well-interference.
Flow-Geomechanics-Geochemistry Simulation of CO2 Injection into Fractured Sandstones and Carbonates
Authors: Mura Miki , Sharma Mukul M.
Published: October 2023

CO2 storage in reservoirs with natural and/or induced fractures is an efficient method to sequester CO2 because of their high and sustained injectivity. Past work has focused on storage of CO2 in the pore space and in the dissolved state within the brine. This research shows that geochemical reactions involving the CO2 interacting with reservoir minerals (in different lithologies) can also play a very important role in sequestering the CO2. A fully integrated 3-D reservoir simulator that includes single-phase flow, geomechanics, and geochemistry is introduced. The geochemical capability in the simulator predicts flow and geomechanical behavior due to geochemical reactions triggered by CO2 injection. The simulation models a reservoir with an induced planar fracture. The amount of CO2 that is sequestered and the extent of mineral dissolution and precipitation are computed. To demonstrate the impact of rock lithology, the model is used to simulate CO2 injection into a sandstone, a limestone, and a dolomite reservoir. The paper also investigates two different CO2 rich brines to investigate the impact of the brine composition. It is shown that the portion of the CO2 injected that reacts with the minerals and is then converted into other mineral precipitates depends largely on the mineralogy of the reservoir and the composition of the injection fluid. Limestone and dolomite reservoirs are much more susceptible to mineral dissolution and precipitation resulting in more CO2 sequestration and larger changes in injectivity over time when injection fluid is compatible with the host rock. It is shown that the fracture geometry determines the location of mineral dissolution and precipitation. This alteration of the mechanical and flow properties of the reservoir rock and fractures resulting from mineral alteration can also change the mechanical properties of the rock and result in more fracture growth and enhance or impede propagation of CO2 plume or CO2 charged water. Results showing the pros and cons of injecting CO2 into fractured wells in sandstone and carbonate reservoirs are presented considering the brine types to charge CO2. Our results show, for the first time, the clear differences that arise when sequestering CO2 in limestone, dolomite and sandstone reservoirs. The impact of geochemical reactions in realistic injection well scenarios is quantified. Results are also presented to show the pros and cons of using hydraulically fractured wells for CO2 injection in both lithologies.
Novel Ways of Optimizing Production of Gas Wells Suffering from Downhole Salt Deposition
Authors: Janzen M. R. , Hornstra E. , Doldersum B.
Published: October 2023

Downhole salt precipitation is an increasing problem in the mature gas fields of the North Sea. With depletion and relatively high drawdowns, excessive evaporation of production water leads to salinities exceeding the solubility limits and thus salt deposition. This leads to significant losses of production and reserves, and increased costs as wells are traditionally shut-in, waterwashed regularly and/or choked back heavily.

Two novel solutions have been conceptualized and applied, the first being installation of velocity strings. Besides increasing gas velocities to eliminate liquid loading, a smaller tubing has a downhole choking effect and as such strongly increases flowing pressures. A case study is presented wherein four velocity strings were set, leading to a strong increase in platform flowrate and extension of asset life. The major advantage of this solution is that it is relatively simple, extremely robust and does not involve any increased OPEX. As it involves increased flowing pressures, it is best applied to lower quality producers. Due to their steep inflow performance relation, there is only a very limited decrease in flowrate upon installation of the smaller tubing.

For good to excellent quality reservoirs, the choking effect by a velocity string causes a flowrate decrease of often 40 to 50% - too significant to yield attractive economics. As such, it is a better option to compensate for the evaporation rate by external supply of freshwater. Proof of concept has been delivered for 1) using recycled low salinity/oxygen process water for water washing and 2) continuous downhole freshwater injection by a successful three-week pilot test. During the latter, injection rates of approximately 1 m3/d have been achieved, which is shown to effectively eliminate downhole salt deposition for the presented case.
Modeling and Optimization of Mud Cap Drilling for Undrillable Wells Due to Loss of Circulation
Authors: Saihood T. , Al-Safran E. , Nguyen T.
Published: October 2023

Mud Cap Drilling (MCD) is a technique from Managed Pressure Drilling (MPD), which is used when all conventional attempts fail to solve the loss of circulation. MCD places a very high drilling fluid density, called Mud Cap (MC), in the annulus above the lost zone to prevent the mud from returning to the surface. A sacrificial fluid instead of drilling mud is used to clean the hole and transport the cuttings into the loss formation. This study presents a detailed step-by-step model and design for a well in the Middle East. New equations were developed to calculate the MC height, MC density, and the position of the interface between the MC and the sacrificial fluid. The present model also depicts pump rate optimization and hole cleaning to reach an efficient drilling program. The case study presented within this paper encountered a complete lost zone and was considered as an un-drillable well. The pore and fracture pressures were calculated using drilling data from the offset well. A sensitivity analysis was performed to obtain optimal MC height and density. A complete optimal MCD design and optimal MCD operation for this well is conducted in detail. The results of this study have proved that the proposed model can be utilized as a tool to design and optimize an MCD program.
Case Study of Successful Pilot Polymer Flooding to Improve the Recovery of Lloydminster Heavy Oil Reservoir- West Central Saskatchewan
Authors: Ulovich Ivan , Imqam Abdulmohsin , Martinez Juan , Aljubori Ahmed , Rathod Rakeshkumar
Published: October 2023

The Lloydminster Heavy Oil Block is the main source of Canada's conventional heavy oil production. The most common methods of recovery in this area are primary production, waterflooding, and chemical-enhanced oil recovery (EOR) such as polymer flooding. Although heavy oil waterfloods could be relatively successful if managed properly, their production and economic efficiencies are often challenging due to quick water breakthrough followed by a steep decline in oil production. Beliveau (2009) showed that over 50% of oil produced from such water flood projects are typically produced at water cuts greater than 90%, which would increase water processing costs. The objective of this study is to outline the implementation of a successful polymer flood project in Lloydminster Heavy Oil Block that includes the production and injection performance of the pilot. It also describes the steps of selecting the appropriate polymer type based on reservoir rock properties, water quality, and other main parameters for the optimal polymer selection. An anionic polymer candidate provided by ZL EOR Chemical Ltd. was selected for the project. The field under study is in the province of Saskatchewan and producing from the Lloydminster sandstone. Initially, the field was produced under a line drive waterflood with horizontal wells. The reservoir has a live oil viscosity of about 2,600 cP at downhole temperature of 21.5°C and the average clean-sand permeability of 1,500 mD. In April 2018, a polymer flood pilot was introduced as a primary recovery method with continuous polymer injection at ~25 cP (~2000 ppm polymer concentration). Injection rates varied from 30 to 50 m3/d/well, based on the target injection volume of 5 to 10% of effective pore volume (PV) per year. As a result, field water cut has decreased and stabilized at ~65%, while oil production rate has remained relatively constant at ~40 m3/d for over five years with no signs of polymer breakthrough. Production performance from the beginning of the polymer flood demonstrates the efficiency of this EOR method, thereby providing valuable insights into the first primary polymer flood project in the Lloydminster Heavy Oil Block.
The Use of Chemical Tracers for Identifying Location of Completion Equipment Failure
Authors: Sennour Bel , Lavoie Scott , Williams Brock
Published: October 2023

This paper reviews the case history of a subsea well in the Gulf of Mexico that was completed with two zones that contained sliding sleeves for the purpose of closing off one zone if early water break-through occurred.

Chemical tracers in solid form were integrated into the sand face completion at both locations. These tracers take the form of rods that can be installed into standard sand screens during manufacturing without modification to the screen. The tracer rods at each location release a unique chemical compound into the oil flowing from the interval. Samples of the produced oil are analyzed to determine the concentration of each unique tracer compounds from each interval.

Upon well startup, the chemical tracers indicated that one sliding sleeve was RIH in the closed position. This insight triggered an intervention to open the sleeve, and the well was restored to expected production rates. The chemical tracers saved the operator from having to intervene into a live well to diagnose below-expectation performance.

The solid chemical tracer technology can be used to monitor any completion component that is designed for separating and sealing off a production interval without incurring the high cost and risk of performing surveys on a flowing well. In addition, this technology can identify locations of water influx, gas influx and inflow distribution through several years of the well’s life.
Autonomous Drilling Fluid Management System - Development of Fluid Advisory System and First Lab Trial
Authors: Ettehadi Reza , Onegova Elizaveta , Fevang Finn Øivind , Knizhnik Alexey , Postovalov Sergey , Brevik Jan Ove , Thompson Jr Charles , Egorenkova Tatyana , Kaageson-Loe Nils
Published: October 2023

This paper details a study to design a Fluid Advisory System which uses various algorithms and methods to calculate an optimal quantity of chemical additives which preserve the desired characteristics of the drilling fluid based on manual and real-time measurements while taking inventory into account. The algorithms and results of the first lab trial are presented for water-based mud.

The Fluid Advisory System methodology consists of a data pipeline for loading historical data into a master table, a training pipeline for creating a fluid property model (digital twin) using Machine Learning (ML); an automated predictive analytics tool for model selection; and incorporating the predictive models into a prescriptive model that determines quantity of additives to use to achieve a desired set of drilling fluid properties. Given the initial product composition, a set of desired and current fluid properties, the prescriptive model suggests necessary modifications in additive concentrations. This is achieved by setting and solving an optimization problem.

First, the Autonomous Fluid Management algorithms have been validated in small-scale lab experiments. Following these successful experiments, a yard-scale trial was conducted at the Equinor Sandsli Automatic Drilling Fluid Laboratory. The yard trial demonstrated how remote control of drilling fluid treatment equipment and the Fluid Advisory System can be employed. The results of the tests reveal that it is now feasible to remotely regulate drilling fluid mixing and apply the ML-based Fluid Advisory System to maintain desired drilling fluid properties for weight, rheology, API fluid loss, pH, hardness, and chlorides.

The Fluid Advisory System was developed to aid in the optimization of the real-time drilling fluids treatment process for usage in an Integrated Operations Level 3 environment (IO level 3) and higher (IO level). This takes a step towards autonomous drilling fluid management that will allow for reduction of personnel needed to monitor and maintain a drilling fluid system; more consistent fluid performance and properties; more efficient rig supply chain; lower NPT; safer operations; lower operational cost; and lower carbon footprint.

To our knowledge, this is the first time that a Fluid Advisory System for maintaining multiple properties of a drilling fluid was developed and validated experimentally in a remote-controlled mixing facility.
Improved Operational Capital Allocation Strategies by Quantifying Inflation and Supply Chain Impacts
Authors: Sharma Akash , Emanuel Jeff , Chapman Mark A. , Godwin Jonathan
Published: October 2023

Asset planning is a critical and complex part of the oil and gas industry, further complicated by recent inflationary and supply chain issues. The present paper focuses on these challenges and recommends an integrated approach incorporating service market fundamentals, commodity fundamentals, cost inflation, and sensitivity analysis to better plan asset development and capital deployment via service cost modeling. Successful oil and gas operations require the sourcing of a variety of complex goods and services. Each of these may have similar or different market factors impacting their pricing performance. The present paper tackles this challenge by leveraging a multivariate regression modeling approach. This modeling technique establishes relationships between raw cost drivers like the WTI Prices, steel cost, labor, etc. and cost of oilfield materials, goods, and services. These costs are sourced as aggregated information of transactional prices to maximize accuracy. We then present quantitative forecasts for these prices and how they impact the overall well and asset cost.

The resulting model provides critical insights into key oil and gas operational goods and services and their correlation with key market factors. By incorporating time-based optimization, the lags between market drivers and their impact on cost can also be understood. The models all showed significant predictability with R-squared values greater than 0.75. The authors find that this approach will help companies make informed decisions about contract and procurement strategies to improve their bottom line. The paper presents a novel approach to asset planning capital allocation by incorporating market and commodity fundamentals, cost inflation, and sensitivity analysis into a multivariate regression modeling framework for service cost forecasting. The resulting model provides valuable insights into the key operational commodities and their correlation with key market factors, enabling companies to make more informed decisions about asset planning.
A Comprehensive Review of Screen Plugging During Openhole Sand Control Completions Installation; Causes, Consequences and Best Practices
Authors: Beldongar Maye , Gadiyar Bala , Jeanpert Julie , Whaley Kevin , Jackson Philip , Carpineta Gabriele , Luppina Salvatore , Farina Lisa , Giammancheri Michele
Published: October 2023

In openhole completions, screens are one of the very common equipment used to control production of solids. Screens could get plugged during installation in case of improper wellbore fluid conditioning and displacement. Awareness of screen plugging is not widely spread and many practicing engineers do not pay enough attention to its implications. This paper will discuss the causes, consequences, ways of determining plugging and recommend best practices to the reduce risk of screen plugging.

The paper will first review the various reasons for screens to get plugged during openhole completion installations and explain in detail undesirable events caused by screen plugging such as:

Inability to properly displace wellbore fluids Inability to fully pack the screen annulus Damage to screens during displacement and gravel packing

It will also review downhole gauge data of several jobs to identify and discuss screen plugging signatures and its outcomes. Additionally, the paper will discuss potential preventive measures.

In openhole completions, it is very common to run screens in wellbores containing solid laden fluids intentionally or unintentionally. Poor wellbore displacement or improper fluid conditioning can result in leaving some bigger size solids in the screen running fluid which could plug the screens. Also, the exposure of reactive shales to water base fluids can destabilize the shales and lead to plugging. In some cases, the screen running fluid quality control (QC) is not properly accounting for the actual flow inside the screen while running in hole resulting in a false pass.

The paper will present several case histories of downhole gauge data analysis showing evidence of screen plugging leading to excessive treating pressure, incomplete gravel pack and in few cases screen erosion during gravel pack operations. To prevent screen plugging it is necessary to properly model all the displacement stages, pay attention to proper conditioning and QC of the fluid and ensure compatibility of the fluids with shales.

A comprehensive review of screen plugging during sand control installation phase and its potential consequences supported with extensive downhole gauge data has not been previously published. This paper will be a valuable source of knowledge for completion engineers and help them better design and executed future operations.
Deep-Learning-Based Approach for Optimizing Infill Well Placement
Authors: Zhang P. , Gao T. , Fu J. , Li R.
Published: October 2023

This study introduces a novel machine learning-based framework aimed at optimizing well placement for shale development. Traditional well-placement techniques, often reliant on physics-based modeling or empirical assumptions, have proven to be time-consuming and prone to suboptimal results. To address these limitations, we propose a Deep Convolutional Neural Networks (DCNN) based workflow that leverages context-specific algorithms for accurate subsurface-driven infill planning optimization. The framework was validated on real-world data from 2 fields of 630 wells in the Permian basin, successfully replicating the validation dataset with 94% accuracy and reducing the time required for analysis by over 85% compared to conventional methods. Furthermore, the framework demonstrated improved Estimated Ultimate Recovery (EUR) and effective reserve management, emphasizing its potential to enhance the economic viability of shale production.
Feasibility Study of Electromagnetic Telemetry System for Offshore Drilling
Authors: Zeng Shubin , Ashraf Tauseef , Zhang Jun , Huang Yueqin , Chen Jiefu
Published: October 2023

Electromagnetic telemetry (EMT) system uses a downhole source inserted near the drilling bit to send out real-time measurements via low frequency electromagnetic waves. A surface antenna picks up the transmitted signal by measuring the potential difference of two locations. Compared with onshore drilling, EMT system for offshore drilling has two major differences: there exists one layer of conductive seawater and one endpoint of the surface antenna anchors near the seabed. An integral-equation-based simulation algorithm was developed for fast and accurate simulation of EMT system in oil and gas exploitation. How the conductive seawater affects electromagnetic wave propagation is studied by modeling different scenarios by changing water depth, well trajectory, downhole source type, and operating frequency. The success of EMT application is strongly dependent on the formation resistivity between the downhole tool and the surface antenna used to monitor the transmitted signal from the downhole tool. Therefore, it’s important that an accurate prediction of the EMT system performance is performed before planning and performing an EMT job. Theoretical and numerical analysis suggests that EMT technology for offshore drilling behaves differently from onshore drilling because there exists a layer of conductive seawater and the surface antenna must traverse through the seawater to the seabed.
An Analytical Tool to Predict Fracture Extension and Elastic Desaturation for Polymer Field Projects
Authors: AlAbdullah M. B. , Seright R. S. , Machado M. V. B. , Delshad M. , Sepehrnoori K.
Published: October 2023

Induced fractures often play a key role in achieving acceptable injectivity during polymer floods, especially for vertical injection wells. However, fracture extension must be controlled to prevent severe channeling between the wells and compromise the flood performance. This paper presents a physics-based analytical model to predict polymer injectivity and fracture length as a function of polymer rheology, injection rate, and reservoir geomechanical properties. The analytical injectivity model is based on the unified viscoelastic model by Delshad et al. (2008). The injectivity model is coupled with 2-D fracture models: Perkins-Kern-Nordgren (PKN) and Kristianovich-Geertsma- de Klerk (KGD). In addition, the model is coupled with the elastic desaturation curve to predict additional oil recovery due to polymer viscoelasticity as a function of the leak-off rate through the fracture faces. Finally, a sensitivity study is conducted on reservoir properties and polymer rheology to understand the dominant factors that control fracture extension.

The analytical model shows good agreement in injectivity and fracture length with two other fracture numerical simulation models (Gadde and Sharma 2001, Ma and McClure 2017). The degree of fracture extension is a strong function of formation permeability, with relatively short fractures predicted for the high permeability characteristics of most commercial-scale polymer floods. We also examine conditions when relatively high leak-off rates through fracture faces might allow the viscoelastic nature of HPAM solutions to displace capillary-trapped residual oil. This is the first analytical solution for coupled polymer injectivity and fracture-length based on real HPAM rheology that can be used by a simple mathematical software or Excel worksheet. The developed tool can assist field operators in reducing the uncertainty and risk in polymer injectivity and quantifying fracture extension in the reservoir.
The Impact of the Energy Transition on Petroleum Engineering Departments: The Faculty Perspective
Authors: Fahes M. , Hosein R. , Zeynalov G. , Karasalihovic Sedlar D. , Srivastava M. , Swindell G. S. , Kokkinos N. C. , Willhite G. P.
Published: October 2023

We live in a time where there are a lot of conversations regarding transitioning energy systems from a major dependance on fossil fuels towards more reliance on renewable energy sources. Such a transition, no matter the pace and shape it takes, has a direct impact on petroleum engineering education. In this paper, we share the results of a world-wide survey that targeted capturing the perspectives of faculty members regarding the impact of the current state of affairs on petroleum engineering education. We analyze those results under various contexts, which include observing the perspectives and impacts by region, age group, and sex. The questions probe the perception of the faculty members regarding how long fossil fuels will remain a major part of the energy mix, the impact this has on their ability to fund their research and publish their work, the impact on recruiting students and on strategic directions in the academic programs, and what the faculty need in order to maintain a curriculum that is relevant to the future careers of their students.

The results reveal that the vast majority of faculty see in the energy transition an opportunity for change in petroleum engineering education. Over 95% of respondents support covering the topics of environmental sustainability, clean energy, and data analytics in the undergraduate petroleum engineering curriculum, with the majority suggesting data analytics be covered as a mandatory course, clean energy as optional electives, and environmental sustainability be included to supplement existing courses. Most faculty are willing to invest the time and effort needed to make the necessary changes to the curriculum, but many do not feel prepared to make some of those changes. The resources faculty identify as useful to be made available to them include well-designed in-person networking events with industry professionals and facilitated learning communities for petroleum engineering faculty. There is no overwhelming support for changing the name of the degree, and most faculty believe that the change should be a process of continuous improvement rather than undergoing a major disruption. There is variability by region in the impact the current challenges have had on industry support for academic research, and variability by age group regarding how long fossil fuels will remain relevant.
New Insights on Catalysts-Supported in situ Upgrading of Heavy Oil During in situ Combustion Oil Recovery
Authors: Fassihi M. R. , Moore R. G. , Pereira Almao P. , Mehta S. A. , Ursenbach M. G. , Mallory D. G.
Published: October 2023

As part of GHG reduction initiatives, there have been many publications on CO2 capture, utilization, and storage (CCUS), reducing the carbon footprints in the oil and gas production, switching to renewable energies, and generating carbonless fuel (e.g., H2) via in situ processes. In situ upgrading of bitumen and heavy oils and converting them into low sulfur, low N2, and low asphaltene can help with both producing cleaner fuel as well as utilizing vast resources of energy that could otherwise be wasted due to extreme measures of no fossil fuel policies. Additionally, such processes could produce valuable products, enhanced shipping/pipelining, and less demanding downstream processing. Generating hydrogen could be another focus area for in situ upgrading.

This paper provides new insights into the results of several combustion tube tests that were performed for Alberta Ingenuity Centre for In Situ Energy (AICISE) using different heavy oils with fresh supported catalyst. The catalysts were placed in the production end of the combustion tube so oil would pass over the catalyst bed before being produced. In practice, solid catalyst particles could be placed into the oil-bearing formation adjacent to the producing wellbore, ensuring that crude oil will flow over the catalysts during oil production. This paper utilizes many of the lab results that have never been published before. The objective is to understand whether using catalysts has merits in our future oil production activities under the current environmental restrictions. A commercial Ni/Mo catalyst was used in these tests. The results of these tests indicated at least temporary significant occurrence of reactions such as: hydroprocessing (HP), hydrotreating reactions, such as hydrocracking (HC), hydrodesulfurization (HDS), hydrodenitrogenation (HDN) and hydrodeoxygenation (HDO).

We will discuss the impact of pressure, temperature, water injection and dispersed versus supported catalysts on the degree of oil upgrading. Also, the key parameters that could impact in situ hydrogen generation will be presented. Specifically, the role of reactions such as Aquathermolysis (AQ), thermal cracking (TC), water-gas shift reaction (WGS) and coke gasification (CG) will be discussed. Notice that the products of these reactions could undergo additional methanation reactions (ME) which could reduce the H2 concentration in the produced gas. Finally, methods of upscaling these results to the field conditions will be presented.
Efficient Deployment of Distributed Temperature and Acoustic Sensing of Three Wells Using Fiberline Intervention Technology
Authors: Alaseri Ghassan , Bukhamsin Ahmed , Garioch Andrew , Abdulghani Ahmed
Published: October 2023

Fiber optics has been an emerging technology in the oil industry as it provides critical downhole data from the well. However, running fiber in the well has been mainly limited to new constructions or through costly coiled tubing operation. This paper describes a novel method to deploy fiber in existing wells and collect distributed and single-point data. This was demonstrated through a successful and low-cost logging operation.

FiberLine Intervention (FLI) employs a unique conveyance method to deploy the fiber inside the well. Two fibers (single-mode and multi-mode) with total length of more than 25,000ft have been wound inside a tool length of around 3ft, which can then unspool from the tool as it drops down the well by gravity. The tool utilizes bare optical fiber and housing materials that will degrade in the well, so it does not disturb production after completing the job.

The end of the fiber is equipped with an electronic gauge to measure single point pressure while the fiber itself can be interrogated to provide Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS) data. Real-time data monitoring capability is enabled by connecting the top of the fiber to a surface laser box.

Normal practice to deploy sensing and monitoring logging tools is to use slickline or wireline. Operational costs and time are of particular concerns, especially when there is a need to bring rigging equipment. Regarding this matter, FLI technology surpassed the conventional slickline by consuming only 15 minutes from releasing the electronic probe to reach the hold-up depth. During this time, DTS, DAS, pressure and temperature data were recorded in real-time. The location of the tool could be confirmed by the fiber loss plot, which shows excessive losses in the still spooled fiber within the probe, and normal losses in the fiber deployed in the wellbore. After the tool has reached the target depth, the annuli were bled of and the DAS responses were monitored to check for any leak in the completion.

The presented field trial represents a successful logging operation, starting from tools setup to the data quality. This breakthrough could be viewed as a starting point as further developments can consider using this as a platform to deploy more variety of sensors downhole.
Attention Mechanism Neural Network for Seismic Facies Classification
Authors: Ang C. T. , Sajid M. , Elsheikh A. , Alsalmi H.
Published: October 2023

Identifying seismic facies groups from seismic data includes tasks such as interpreting structures and assigning facies information into the identified structures. The process of seismic interpretation relies on expert interpretation and is generally time consuming. In the current work, we develop a new network architecture for automatic seismic facies class with attention mechanism for improved classification results.
Overcoming the Obstacle of Reservoir Stimulation Through ICD Completion - The First Approach of Valvular Conduit for Inflow and Outflow Control Devices
Authors: Nugraha Ikhsan , Siham Ahmed , Widjaja D. , Nasir H. A.
Published: October 2023

Horizontal wells often require production control along the open hole. This is achieved by installing appropriate Inflow Control Devices (ICD) configurations that introduce higher restrictions across flow dominant zones and less restrictions across poorer quality zones respectively. Although these restrictions are designed to allow normalized production across the entire horizontal section, it can adversely impact the control of injection rates across the horizontal section during acid stimulation jobs. This paper intends to discuss a new approach to overcome these limitations and allow injection of the desired rates resulting in more effective acid stimulation works.

To overcome injection rate limitation during stimulation, a new valvular conduit flow profile was tested for ICD application. It relies on dynamic diversions and collisions of the fluid flow in series to provide restrictions, hence pressure drop. The valvular conduit geometries were adjusted to achieve desired flow restrictions that are equivalent to nozzle ICD in production direction. When the flow is reversed, valvular conduit profile ICD significantly reduces fluid diversions and collisions resulting in higher rate in injection direction for the same applied pressure drop.

These unique features were taken into ICD near wellbore modelling workflow in conjunction with available well and reservoir properties to evaluate its performance and operating envelope. Furthermore, stimulation model was studied for the new completion impact on fluid distributions as well as acid penetration in to the reservoir matrix.
Improvement of Polymer Flooding of a Viscous Oil by Addition of an Alkali
Authors: Guo Yujia , Shi Yue , Mohanty Kishore
Published: October 2023

Polymer flooding has been applied successfully in many water-wet, viscous oil reservoirs. When the reservoir is intermediate-wet or oil-wet, the polymer dosage has to increase to keep the displacement front stable, which adds to the cost. Alkali can generate in-situ soap, which lowers interfacial tension and may change wettability; therefore, alkali-polymer (AP) flood can be considered as an alternative way of improving recovery without increasing polymer concentration. This work studies the effect of alkali addition to polymer floods in displacing viscous oils from sand packs and carbonate packs of various wettability. Sessile drop contact angle (SDCA) and water drop penetration time (WDPT) measurements were conducted to evaluate the wettability before and after alkali treatments. The floods were conducted in a custom-designed 2-D visualization cell. The results show that the alkali was able to reduce the IFT between the viscous oil and water to 0.07 dyne/cm. SDCA and WDPT results showed that the sand pack with an initial water saturation (Swi) tends to be water-wet, while that without Swi tends to be intermediate-wet. The carbonate pack was tested to be strongly oil-wet even at Swi. Alkali was effective in making the intermediate-wet sand more water-wet, but has a limited effect on the oil-wet carbonate. Coreflood results show that in water-wet sand packs, the AP flood with a viscosity ratio of 10 results in a stable displacement with an incremental oil recovery of 7% OOIP compared to the straight polymer flood of the same viscosity ratio. In intermediate-wet sandstone packs, the AP floods were unstable, and early breakthrough was observed. However, the oil recovery of AP floods was still 5% higher than the straight polymer flood at 2 PV. AP flooding in oil-wet carbonate packs recovered 18% additional oil at 2 PV injection than the polymer flood at the same viscosity ratio. This study suggests that the efficiency of polymer foods can be improved by addition of an alkali.