bluuebunny/crossref_metadata_2025 huggingface dataset:
HELMINTHOPSISANDCYLINDRICHNUSICHNOGUILDS FROM MIOCENE THIN-BEDDED TURBIDITES, TIERRA DEL FUEGO, ARGENTINA
Authors: OLIVERO E.B. , LÓPEZ CABRERA M.I.
Published: October 2023

Miocene thin-bedded turbidites from Tierra del Fuego record scarce graphoglyptids and two unusual ichnoguilds composed of diminutive elite trace fossils. The first, a monoichnospecific Cylindrichnus ichnoguild, consists of crowded, post-depositional burrows formed in surface sediments during the final phase of turbidite deposition. The second, a pre-depositional Helminthopsis ichnoguild, consists of dense aggregates of simple trails, mainly Helminthopsis and Helminthoidichnites, occupying a very shallow tier in organic-rich mud covering the sea floor prior to turbidite deposition. The trace makers of Cylindrichnus were opportunistic suspension/detritus feeding organisms, probably polychaetes, which bloomed during high flux of labile organic matter brought to internal and external levees by turbidity currents. The trace makers of Helminthopsis and Helminthoidichnites were probably nematodes that grazed on organic-rich muddy sediments with abundant disseminated pyrite associated with Kinneyia-like and other problematic wrinkle structures, suggesting sulfur-cycling chemosynthetic microbial communities originated during interturbidite phases. The rhythmical alternation of the Cylindrichnus and Helminthopsis ichnoguilds clearly differentiate the thin-bedded turbidites of the Viamonte Formation from channel-levee complexes elsewhere, stressing the point that ichnoassemblages reflect sets of environmental parameters and not necessarily particular depositional settings.
Microfossils, High-Resolution Stratigraphy, Geochemistry and Lithology of the Upper Jurassic and Lower Cretaceous (Urdyuk-Khaya and Paksa Formations) in the Nordvik Peninsula, Anabar Bay, Laptev Sea
Authors: Nikitenko B.L. , Pestchevitskaya E.B. , Kashirtsev V.A. , Fursenko E.A. , Popov A.Yu. , Khafaeva S.N. , Bragin V.Yu.
Published: October 2023

—The goal of this study was to improve the high-resolution biostratigraphy of the Upper Jurassic and Lower Cretaceous in the type section on the Nordvik Peninsula, Anabar Bay, Laptev Sea. The results were used to identify a succession of 13 foraminiferal biostratigraphic units, 9 dinocyst units, and 8 palynofloral biostratigraphic units in the rank of zones and local zones. Based on new data, the stratigraphic continuity of this section is proved for the Lower and Middle Volgian, where a major stratigraphic hiatus was previously assumed. The established zones have variable correlation potential. Different versions of the subdivision of the section based on ammonites are discussed and the proposed scale is justified. A reference level based on calcispheres/calcareous dinocysts is defined providing global correlations and calibration of beds near Jurassic–Cretaceous boundary in the Tethyan and Arctic regions. The magnetostratigraphic subdivision of the studied section and its comparison with the Tethyan regions are discussed. Together with biostratigraphic data, the proposed δ13Corg curve in the Upper Jurassic and lower part of the Valanginian can be a tool for detailed correlations in different regions of the Northern Hemisphere. The cyclicity of carbon isotope composition in the Upper Volgian and Boreal Berriasian and isotope events in the Volgian and Lower Valanginian are determined within the Arctic region. The distribution of geochemical parameters (Corg, δ13Corg and hydrogen index) is determined in studied section, geochemical stratification of the section and variations in major oxide compositions are demonstrated. A sharp change in geochemical parameters is identified at the base of the Paksa Formation (Upper Volgian). The distribution interval of the “subsurface chlorophyll maximum” is determined. The study shows that high concentrations of isotopically light organic carbon in the first diasterene geochemical subhorizon were caused by high phytoplankton productivity and were deposited under reducing conditions favorable for preservation of organic matter. The analysis of major oxide compositions of the studied rocks revealed that variations in the chemical composition of the studied rocks reflect changes in their mineralogy and petrography.
More Career Development Learning for Neurodivergent Tertiary Education Students: A Case Study
Authors: Coffey Jane , Lovegrove Emma
Published: October 2023

All adults, regardless of neurodivergent condition, should have the opportunity to engage in meaningful and sustainable work. However, there are a range of unique barriers facing those with neurodivergent conditions which are critical to understand to successfully facilitate the career development learning (CDL) strategies that will enable job market entry and success. In this paper, we will discuss a pilot CDL program, founded on the principles of social constructivism and Students as Partners (SaP), which was developed to provide neurodivergent tertiary students with the necessary skills and information to establish meaningful careers and employment options.
Through our study, findings underscored the anxiety many neurodivergent students experience around career development and the need for specialised support to build confidence. Significantly, the most impactful outcomes from the program were the ability for neurodivergent students to hear authentic and relatable stories from their peers. The opportunity to discuss both successes and obstacles through the lens of neurodiversity was a powerful mechanism within which to build a learning environment as well as a sustainable community of practice. The experiences in both designing and conducting the Students as Partners driven CDL workshops for tertiary neurodivergent students adds significant value to the existing body of literature in not only how we define and label disability but also how employability is interpreted, both from academic and industry perspectives. The observations and findings of such an approach also challenge the existing narrative embodied in many university graduate capability programs for a changing future of work landscape.
New NMR Porosity Correction Algorithm for Steady-State Buildup Effect in Unconventional Reservoirs
Authors: Bordakov G. A. , Utsuzawa S. , Allen D. F. , Karpekin Y. , Rose D. , Troyer W. , Laronga R. J. , Bachman H. N.
Published: October 2023

Nuclear magnetic resonance (NMR) logging for subsurface exploration is gaining acceptance as an everyday measurement for conventional and unconventional reservoirs, as well as new energy applications such as carbon storage and geothermal formation evaluation. Out of many NMR sensor designs, ones with a saddle-point magnetic field profile have gained broad acceptance because of their short echo spacing and many operational advantages. Despite bringing advantages, the saddle-point design can lead to systematic overestimation of porosity in combination with T1-T2 logging, which has been especially observed in unconventional reservoirs.

We have developed a multiphysics tool model—a digital twin—that quantifies the recently discovered steady-state buildup (SSB) of the NMR signal in a multivalued gradient magnetic field. This effect arises mostly from off-resonance signals. The model incorporates the static and dynamic fields of the NMR sensors, associated physics, and the transmitter and receiver electronics. It is validated by laboratory experiments. This SSB effect has been found to be the key cause of the observed porosity overestimation, which is most significant in unconventional and carbonate reservoirs.

The application of the digital twin has allowed us to improve the tool forward modeling accuracy by calculating the correction factors for each combination of T1, T2, pulse sequence, and environment. A new kernel-corrected NMR inversion has been developed. The novelty of the inversion includes not only a forward modeling correction, but also post-inversion correction for the bias caused by regularization and an additional procedure for the reduction of the artifacts particularly evident at short relaxation time constants. The overall improved inversion delivers accurate, higher-definition T1-T2 maps that were not attainable before.

Validation of the new inversion has been performed on field datasets. Results demonstrate reconciliation of kernel-corrected NMR porosity with independent porosity measurements in unconventional and conventional formations. High-definition maps enable better segregation of different fluid types in unconventional reservoirs and delineation of producible intervals with increased clarity and confidence.
Best Practices Applied in Drill Stem Testing of HPHT Wells With the Presence of Very High H2S and Super Saturated Saline Water in the State of Kuwait
Authors: Al-Ajmi Bader , Al-Ateeq Abdullah , Kumar Munna , Abdullah Abdulkareem Mohammad Ibrahim
Published: October 2023

Objective/Scope

The objective of this paper is to present the best practices applied in drill stem testing of wells with harsh environment due to presence of high sour fluid. For the first time in State of Kuwait, five exploratory wells were tested with several challenges namely high pressure, high H2S (~ 40%), super saturated saline water leading to salt plugging both at surface and downhole, flaring / safe disposal of produced well fluid, intervention using coil tubing for activation and acid stimulation, rates measurement, production logging and bottom hole sampling etc.,. Best practices of well test along-with fit for purpose equipment were used. This resulted in successful data collection of the subject wells without any damage to personnel and environment.

Method, Procedure, Process

Five deep Jurassic wells were drilled with heavy mud 18.9 - 20.4 ppg to 11,107 ft. - 15,550 ft. targeting new formations with many anticipated challenges like high pressure 10,900 - 14,500 psi, high temperature 220 - 260 degree F, and ultra-sour reservoir fluid with H2S concentration up to 40%, super saturated saline water with water cut up-to 100%.

The operational challenges were suitably addressed by means of meticulous planning, application of additional equipment and alternate approach. Continuous dozing of H2S inhibitor & scavenger protected surface test lines & equipment. Flow measurement is accomplished by using multiphase flow meter in addition to test separator to handle very high H2S concentration. To achieve uninterrupted flow and to avoid/overcome salt plugging at surface, continuous brackish water pumping arrangement was installed in the upstream line of choke manifold. For continuous uninterrupted produced fluid disposal & flaring, two flare-pits with green burners are made to avoid well closing due to unfavorable wind direction. Bottom-hole samplers were deployed on DST test string facilitating to capture representative reservoir hydrocarbon samples as and when required. During coil tubing intervention for well activation & downhole salt bridges clearing, continuous H2S inhibitor pumping was done. All safety precautions was adhered as per company norms for H2S monitoring and handling. Wireline production logs remained a challenge in these well wells due to harsh environment.

Results, Observations, Conclusions

Setting up suitable measures helped in executing successful well tests in new formations without any damage to personnel and environment.

Novel/Additive Information

For the first time in State of Kuwait, in five deep HPHT wells, new formations with many challenges were tested successfully. This resulted in a new level of confidence to execute testing operations in extremely harsh environment and encouraged in Exploration activities.
Improving Velocity Modeling with Surface Drilling Data Using Machine Learning
Authors: Gong B. , Hossain A. , Sanclemente K. A. , Alli O. G. , Harvey B. , Wang K.
Published: October 2023

Subsurface velocity models play a vital role in the conversion of seismic data from travel time to horizon depth. However, in practice, the calibration of velocity models can be challenging due to the limited availability of sonic logs. As a result, depth uncertainties may be introduced to the seismic images, potentially impacting the accuracy of geological interpretation. In this paper, we leveraged the known correlations between drilling parameters (e.g., rate of penetration, weight on bit and torque) and mechanical properties of formation rocks to construct a machine-learning model that estimates sonic velocity. Trained with well data from an unconventional field, the model successfully generated predictions that closely tracked actual sonic logs in blind test wells.

The workflow consists of data preparation, exploratory data analysis (EDA), modeling and testing, and interpretation. The steps of data preparation and EDA were both conducted with the guidance of domain knowledge to ensure any preprocessing and interpretation are contextually reasonable. In the modeling phase, a two-stage Random Forest regression model was trained and fine-tuned, in which the second-stage model learns from the residuals from the first-stage predictions. Overall, the model demonstrated effectiveness by capturing the trend of sonic velocity with respect to depth across the majority of intervals. We observed that the prediction errors are overall symmetric around zero but varied with depth, which was likely caused by data quality issues in shallower intervals. Among the input features, true vertical depth made the dominant contributions to the prediction, likely due to the low dips and low lateral variability of the local geology. Other key predictors included revolutions per minute, hook load and weight on bit.

By incorporating estimated sonic velocity profiles, the resolution of existing velocity models can be enhanced both vertically and spatially, while avoiding additional costs for data acquisition. In addition, the capability of estimating velocity during drilling offers new opportunities to inform real-time decisions in operations, as updates could potentially be made to the horizons ahead of the bit as new drilling data stream in.
Improving Production Enhancement and Idle Well Reactivation (PE/IWR) Success Rate at Country Level in Malaysia Via PE/IWR Qualifier Matrix Approach
Authors: Bakar Hasmizah , Khairul Anuar Khairina , Mokhtar M Khaidir , Idris Khairul Nizam , Khalid Ruzanna , Abu Bakar Mohamad , Masoudi Rahim
Published: October 2023

Production enhancement and idle well reactivation (PE/IWR) activities have been proven to be more economically attractive and quick win enabler to revitalize Malaysia production landscape as compared to other workstreams such as deferment management, well integrity healthiness, new hydrocarbon delivery and prudent reservoir management plan. A magnitude of approximately 1000 reservoirs mapped to 100+ oil and gas assets across three land masses is roughly the hydrocarbon capacity in Malaysia. Each year thousands of rig and rigless interventions are carried out across 3000 wells completed in shallow and deep water assets that are operated more than 15 operators.

As regulator and host authority for all hydrocarbon resources in Malaysia, it is critical for Malaysia Petroleum Management (MPM) to scrutiny PE/IWR proposals submission by operators not only to maximize production from active strings and improve the idle string management but also to arrest further value leakages. This paper will emphasize the transparent methodology established by MPM team to rank PE/IWR activities which required regulatory approval for execution based on risk value, chance of success and doability on how quickly to realize gain. The prioritization method through PE/IWR Matrix Qualifier ranking starts as early at the stage of yearly work program budget planning and followed by multi-disciplinary technical commercial value assurance committee for final approval. The level of attractiveness of PE/IWR opportunities will correspond to its rating. Those operators with low qualifier rating activities are required to refine the jobs value attractiveness in the event the operators insist to pursue the executions are also outlined in this paper. All prioritized (medium and high qualifier rating), approved and planned opportunities are then turned into execution pipeline and properly tracked into a systematic methodology for post job analysis, evaluating the success of the jobs and recording the lesson learned for improved future jobs quality.

Value proposition of PE/IWR Matrix Qualifier in MPM more than a job prioritization tool comes through intensification of ranking efforts and standardization process for PE/IWR budget approval of overall Malaysia hydrocarbon assets to realize business production target. This approach is one of the factors that has significantly improved 2022 PE/IWR gain by 22% against last year actual gain, increased the activities success rate from 52% to 65% with substantial USD16million cost avoidance for unnecessary spending. The authors would also like to share their experience as devoted Shapers and Enablers to safeguard Malaysia production target that may inspire other petroleum authorities in transforming the ambition(s) into action.
Maximizing Recovery in Deep-Water Gulf of Mexico Assets. Surveillance in Complex Subsalt Reservoirs
Authors: Cedillo G. , Zett A. , Han X. , Peraser V. , Gelvez C. , Saidian M. , Ortego A. , Mammadli R.
Published: October 2023

Deep water surveillance in the Gulf of Mexico (GoM) is a very challenging and capital extensive commitment for operators. Maximizing production by understanding reservoir storage capacity and deliverability is a complex task as multiple realizations could be drawn using permanent gauges and production rates, especially when the well is not performing as expected.

Gathering petrophysical surveillance that supports well work and, or well remediation in wet tree production systems is complex and challenged by well access, environment conditions (high flow rates, high pressure) and availability of sensors that provide representative measurements in such conditions. To maximize the outcome, efficient combinations of sensors are designed to provide reliable reservoir surveillance and well integrity data. The data is holistically combined to provide a quick turnaround for results that feed into decisions trees, that reduce rig time and minimize the production deferrals.

In this paper we present the results of a novel sand detection instrument suitable for deep-water environments. We also present holdup instruments combined from different vendors in the same wells to address the high flow rate quantification limitations due to friction and flow regime changes. We will share several examples of time-lapse cased hole fluid saturations in complex well completions. We will share a workflow that proved successful over the recent downturn in the industry. This workflow addresses the uncertainty in nuclear attributes by using flow diagnostic sensor integration as constraints.

Currently, we are the only operator in GoM running active surveillance in deep water wet trees >25k ft. This paper shares the novel techniques and instruments used to evaluate different types of surveillance and how they contributed to maximize recovery by measuring key parameters critical for reservoir modelling, such as fractional flow, time-lapse residual saturations, or flow rate splits per reservoir.

Challenging the industry status quo enables us to change the game in flow diagnostics determination in our high value wells. By identifying new sensor combinations that complement the existing technology offer with novel workflows and the inventive approach to progress such solutions, we are happy to share our success and lessons learned.
Impact of Salinity and Temperature on Wormhole Generation Due to CO2 Sequestration
Authors: Aldhafeeri Abdullah , Mirzayev Elvin , Aljawad Murtada Saleh , Al-Ramadan Mustafa , Ibrahim Ahmed Farid , Al-Yousef Zuhair , Almajid Muhammad M. , Al-Ramadhan Ammar Mohamad , Al-Yaseri Ahmed
Published: October 2023

Deep saline aquifers are good candidates for carbon dioxide (CO2) sequestration. The reaction between the CO2 gas and the saline water aquifer creates carbonic acid (live brine) that reacst with the formation rock to generate wormholes. As a result, the rock mechanical properties will be altered. The goal of this study is to understand the impact of salinity and temperature on creating wormholes due to live brine injection.

Limestone core samples (1.5 × 3 inches) with a permeability of 2 – 4 mD and 15-17% porosity values were selected to perform the study. Coreflooding experiments were performed, after which the samples were scanned to observe the wormhole generation and the change in the pore structure. Carbon dioxide was mixed at 2,000 psi with a ratio of 30% CO2 to 70% brine to formulate a live brine. The live brine was injected into the rock samples at different temperatures (35 °C, 60 °C, 85 °C). Also, CO2 was mixed in the brine width with different salts concentrations (40,000 ppm, 120,000 ppm, 200,000 ppm), which were then injected into the rock samples to test the impact of salinity. The mechanical properties of the samples before and after wormhole generation were studied using impulse hammer and acoustics.

The injection of the live brine generated wormholes in all low-permeability rock samples. Due to the wormhole's generation, the rock samples' porosity and permeability increased significantly. The time to generate the wormholes has a positive relationship with the salinity and temperature. For instance, it took around 5.5 hrs of live brine injection at 1 cc/min to create a wormhole at 35 °C, while it took more than 10 hrs at 85 °C. Similarly, it took only 3 hrs to generate womrhole in the low salinity samples while double the time for the high salinity ones.

This research's novelty stems from its application to CO2 sequestration by investigating the salinity and temperature of saline aquifers. These two parameters are significant ones that distinguish aquifers. This is the first study to understand the impact of salinity and temperature on wormhole generation due to CO2 sequestration.
Impact of Well Interference on Transient Pressure Behavior During Underground Gas Storage: A Comparative Study
Authors: Chu Hongyang , Zhang Jingxuan , Li Jiawei , Zhu Weiyao , Ma Tianbi , Gao Yubao , Lee W. John
Published: October 2023

Underground natural gas storage (UGS) is key to achieving carbon neutrality and it is also a potential solution to the seasonal imbalance between gas supply and demand. To store or withdraw a large amount of natural gas within a specified time, wells in UGS projects often need to have high continuous injection and withdrawal capacities. High injection and withdrawal rates lead to uneven pressure distributions in UGS and substantial well interference. This paper proposes an analytical model to investigate the impact of well interference on transient pressure behavior in UGS wells. We used Laplace transforms and the Stehfest numerical inversion algorithm to obtain an analytical model of the pressure response of a vertical well in a UGS project. We used the superposition principle to model well interference effects, and we used a commercial numerical simulator to validate analytical solutions for different cases. Results show that the pressure behavior during interference depends mainly on the operational status of adjacent wells. When an adjacent well is withdrawing gas, interference causes the pressure derivative to first rise and then flatten later. When gas is injected into the adjacent well, the pressure derivative curve drops continuously and is similar to the shape for a well near a constant pressure boundary. The types of adjacent wells affect the rate of rise of the pressure derivative curve at later times. Interference with a target well is more likely when we inject into or produce gas from a vertical well than from a horizontal well. The application of our methodology is illustrated for the Hutubi UGS. Available data from nine cycles of injection and withdrawal in this UGS project indicate that the cumulative gas injection volume and the gas withdrawal volume were 155.43 × 108 m3 and 130.81 × 108 m3. The final gas storage volume eventually reached 93.5% of the designed UGS capacity.
An Efficient Approach for Automatic Parameter Inversion Based on Deep Learning
Authors: Li Dexuan , Chen Zhiming , Sepehrnoori Kamy , Sun Xiaoguang
Published: October 2023

Parameter evaluations are the first and primary tasks to understand the natural gas hydrate reservoirs. However, there still lacks some effective means for parameter evaluations in hydrate reservoirs. To improve this situation, this paper tries to combine the well testing with deep learning (DL) method for solving parameter inversion problems of natural gas hydrate wells. First, a radially-composite well testing model with dynamic interface is developed to represent the hydrate dissociation driven by depressurization. Then, by Laplace transform, the wellbore pressure is solved and adopted to train a one-dimensional convolutional neural network (1D CNN) and the optimal convolutional neural network (CNN) is obtained by minimizing mean square error. In the CNN, the wellbore pressure is used as input of the network after nondimensionalization, and the interpreted parameters are permeability, wellbore storage coefficient, skin factor and dissociation factor. Finally, the well testing and DL method is verified and applied in a field case.

Results show that the sensitivity of the parameter on pressure transient behavior will affect the accuracy of parameter inversion. The 1D CNN is tested with synthetic data, which shows great practicality and high accuracy of curve matching. During the field application, when compared with manual match, the relative errors of wellbore storage coefficient and dissociation factor by the proposed method are 4.863% and 1.933%, respectively. The proposed well testing and DL method is proven to be suitable for problem inversion of natural gas hydrate wells, which may provide a new tool for engineers to understand the natural gas hydrate reservoirs.
A Non-Portland Cement System: A Step Forward Towards Sustainability of Oil Well Cementing
Authors: Abdelaal Ahmed , Elkatatny Salaheldin , El Fattah Ahmed M. Abd
Published: October 2023

Although ordinary Portland cement (OPC) is widely used in oil well cementing for different applications such as zonal isolation and plugging, it does have technical and environmental drawbacks. Portland cement is responsible for approximately 8% of the global carbon dioxide (CO2) emissions and consumes massive energy while manufacturing. Geopolymer cements, which are made from non-traditional, nonOPC ingredients, have garnered attention as potential candidates for oil well cementing due to their low CO2 footprint, and less energy consumption. This work introduces a proposed non-Portland cement system that totally replaces Portland cement using volcanic tephra (VT) activated by an alkaline solution. The study started by collecting, crushing, and sieving VT until getting fine VT powder. Rheological properties, unconfined compressive strength (UCS), Poisson's ratio (PR), and Young's modulus (YM) were also evaluated for the developed formulation. Sedimentation evaluation was conducted using the API method. The developed VT based geopolymer used sodium hydroxide (NaOH) solution and VT. The 24 h UCS was 3,132 psi with a PR of 0.29 and a YM of 7.69 GPa. It has a thickening time of 3.5 h without using any retarder at 170°F. The density variation between the top and bottom sections was only 0.65 %. This work introduced a new cement system made of VT without any processing except milling and sieving. This reduces the overall carbon footprint, and costs of oil well cementing operations. Moreover, it solves some technical problems associated with the use of Portland cement.
Great Opportunities for Young Professionals in Energy
Authors: Ershaghi Iraj , Paul Donald L.
Published: October 2023

"Scientists discover the world that exists; engineers create the world that never was." Theodore Von Karman

What will be the shape of the future in terms of energy use? What will be the sources of energy? What will be the major changes happening in the energy fields, what changes will result from engineering innovations, and how can AI and digital technologies change the energy engineering fields? Are there still opportunities for petroleum engineering graduates? How should the PTE curriculum be changed?

The combination of Energy Transition and AI are two areas that will materially impact the shape of the future of energy. Integral will be the developers, scientists, and engineering professionals, involved in innovating new directions, and therefore, more talent must be recruited and developed to add to the workforce who can impact these areas.

With regard to the forecasts of future energy and supply, major international organizations such as IRENA and IEA, are of the opinion that despite positions taken by some interest groups, the immediate phasing out of fossil energy is unrealistic. However, more immediate progress is needed to reduce the carbon intensity and emission levels from energy production and use. Advancing the development of capabilities such as economic direct air capture processes, converting the CO2 from power plants and convenient personal and public transportation to other useful products, and planning subsurface storage of CO2 at scale, are all likely to be needed to curb the global CO2 emissions loading.

These all create great opportunities for the advanced subsurface and operational expertise needed to drill, complete, and produce wells to communicate with subsurface storage systems. Also needed are more chemical engineering innovators and talents to focus on economical (DAC), Direct Air Capture, solutions, and carbon dioxide conversions.

In parallel, the advent of AI applications is revolutionizing how we can conduct oilfield operations and process dynamics. Major educational content and training changes can make petroleum engineering professionals perform functions with lower carbon emissions. This creates new classes of opportunities for society and energy-related professionals.
Integrating Learnings from Matrix-Acid Stimulation of Smart Liner Completions – A Template for the Future
Authors: Mogensen K.
Published: October 2023

Smart Liners rely on the limited-entry principle where a number of small holes act to distribute acid along the un-cemented reservoir section. Over the past two years, this technique has become a key method for matrix-acid stimulation of ADNOC's carbonate reservoirs. The objective of this paper is to summarize the learnings from more than 100 deployments and tie together the key elements of the hole spacing design, the stimulation job execution, and the performance monitoring.

A software algorithm generates the hole spacing design to honor a predefined acid flow distribution along the drain length. Quantification of the stimulation efficiency is addressed in several ways. First, the baseline well performance is established with production tests covering several months and in some cases accompanied by a pre-stimulation production logging test (PLT). The stimulation job is then analyzed and compared against a wormhole model to derive the transient injectivity improvement versus acid volume pumped. After the stimulation, the stabilized performance is analyzed in terms of production testing and occasionally a pressure buildup survey and a PLT.

Results have so far been very encouraging. Smart Liners have been deployed predominantly in oil producers and water injectors but a few implementations have targeted tight gas reservoirs. A typical steady-state productivity gain is 100-150% above the baseline unstimulated well and the technique consistently outperforms conventional matrix-acid stimulation techniques. The post-stimulation PLT's show that the entire wellbore contributes to flow, even in extended-reach wells. The majority of the efficiency improvement seems to occur with an acid coverage of 0.5 bbl/ft but some wells benefit from higher acid dosages. A wormhole model developed specifically for this completion-stimulation method can reproduce the observations and helps guide designs of future stimula0tion jobs by suggesting modifications to the hole spacing, which will improve the performance improvement using less acid volume.
Novel Janus Carbon Nanofluids from Waste Plastics as Sustainable Nano-Agents for Enhanced Oil Recovery: Scale-Up Synthesis and Performance Evaluation
Authors: Wang Wei , Chang Sehoon , Gizzatov Ayrat , Thomas Gawain
Published: October 2023

This research reports a new type of useful nanomaterials from waste plastics, Janus carbon nanofluids, and demonstrate potentials of the Janus carbon nanofluidsas high-effective alternative nano-agents for EOR application at reservoir condition. A novelsustainable cost-effective method has been developed to scale-up synthesis of Janus carbon nanoparticles (JC-NPs) from the waste plastic feedstock by combined pyrolysis, chemical functionalization and pulverization processes, which allow to produce the JC-NPs in mass quantity in industrial scale. The Janus nanostructures have been characterized and confirmed by multiple techniques including scanning electron microscopy (SEM), Langmuir-Blodgett (LB) curve, contact angle and interfacial tension (IFT) measurements. Unique dual properties of nanoparticulate and surfactant-like behavior of the JC-NPs have been observed and confirmed. Formulated as nanofluids in brine suspension, the JC-NPs can be directed and assembled at interfaces of rock/fluid or water/oil. Contact angle measurement has shown that the JC-NPs remarkably alternate the wettability of rock surface, and interfacial tension measurements have shown that the JC-NPs can lower the IFTs between brine and crude oil at simulated reservoir conditions. With low concentration of the JC-NPs in nanofluid formula, EOR performance tests have been performed to evaluate the efficiency of the nanofluids for oil replacement in carbonate reservoir with a microfluidic device, and the results have demonstrated that the Janus nanofluids at low concentration could remarkably promote the oil replacement in simulated carbonate reservoirs. The waste plastic conversion appears as an attractive way to produce useful, valuable Janus carbon nanomaterials to decrease the carbon footprint and contribute to the transition toward a resource-efficient chemical industry.
Application of Compressible Carbon in Cement to Mitigate Cement Pore Pressure Reduction and Improve Zonal Isolation
Authors: Wu Q. , O'Donnell B. J. , Stiles D. A. , Benton J. , Freysteinson J. , Johnson K. , Zhou C. , Robin R. J. , Koester S.
Published: October 2023

A quality cement job is essential to ensure long-term zonal isolation in oil/gas and carbon storage wells.This may be affected by the cement hydration process, where water is consumed causing pore pressure reduction, and shrinkage, which increases the risk of fluid/gas invasion, formation of micro-annuli and even the risk of shear bond strength reduction.This paper presents the application of compressible carbon particles as a cement additive to mitigate cement pore pressure reduction and improve zonal isolation. Cement formulations with compressible carbon were designed and evaluated using API standard tests and industry-wide recognized tests to ensure they met functional requirements for well cementing such as: mixability, thickening time, rheology, compressive strength development, fluid loss and free water.The concept is as follows:when cement is pumped into an annulus, the compressible carbon particles will compress under hydrostatic pressure.When the cement is hydrating, the compressible carbon will expand to mitigate the porepressure reduction.To validate the proof-of-concept, a benchtop high-pressure high-temperature (HP/HT) setup and a pilot-scale test setup were developed. A cement formulation with 9% compressible carbon by volume was found to be stable and have controllable performance properties such as thickening time, fluid loss and free water.A control slurry without compressible carbon was designed and tested for comparison.Both the benchtop and pilot-scale tests demonstrated that adding compressible carbon into the cement formulation mitigated the pore pressure reduction during cement hydration.This may reduce the risk of fluid/gas invasion that could result in migration in the set cement.Comparing the cement containing carbon to the control system without carbon, the gas permeability was reduced. The bond strength obtained from shear bond tests improved significantly, which may reduce the risk of debonding and be an indication of the reduction of shrinkage.Additionally, a better hydraulic seal was found in one test, but further investigation is needed.Similar mechanical properties such as compressive strength and tensile strength were measured for both cements with and without compressible carbon.The data showed adding compressible carbon does not have a negative impact on the hardened cement properties.In fact, adding compressible carbon decreased Poisson's ratio slightly. This paper will present the results of proof-of-concept testing for the novel application of compressible carbon in cement to improve zonal isolation by mitigating pore pressure reduction.It will also present new benchtop and pilot-scale experimental setups to measure pore pressure changes during cement hydration.
An Innovative Solution to Regain Well Integrity and Deepening Gas Injection Point - Maximizing Production and Rectifying Multiple Tubing Leaks with a Low-Cost Solution
Authors: Mamat Muhamad Aasif , Zayani Sirag , Alham M. , Johan M. , Kadir Masran , Rahman Saim , Ogueri Chidi , Thian Kelvin , Zafuan N. , Hamid Ali Abdul , Zamudin Budi Kastulani , Arifin Akram , Low Y. Peng
Published: October 2023

Multiple tubing leaks have become one of the major issues in brownfield operations especially on wells that have already exceeded their original production lifetimes. This integrity issue becomes more challenging when the leaks occur close to the tubing hanger due to the space constraints in fixing them.

In addition, high water cut wells with low reservoir pressure require continuous artificial lift where tubing integrity is crucial to allow the injected gas reach to the target injection depth. Conventionally, tubing packoffis used to isolate tubing leaks occurring in short intervals while longer ones require coiled tubing straddle with higher installation complexity. However, some wells need deeper injection than the initial completion design. The wells might not be able to flow efficiently without deepening the gas lift point to optimize production to the full extent.

In finding the solution to all three issues; multiple tubing leaks, low reservoir pressure and the requirement for deeper gas lift point, multiple solutions have been proposed and evaluated. Traditionally, workover is considered the best method to replace degraded tubing and to deepen gas lift mandrels.

This paper discusses an innovative and low-cost solution which has been proposed and successfully executed in a dual strings completion. A conventional coiled tubing straddle is installed in the long string as Coiled Tubing Gas Injection Straddle (CTGIS) for gas lifting and the short string is used for oil production. This system replicates the barrier envelope as per the production casing annulus during gas lifting operations and also deepens the lifting point through a sliding sleeves door (SSD). Injected gas mixes with liquid through the SSD from the long string allowing continuous flow from the short string. This low-cost and quick solution enables the well to be restored to production.

This paper includes the gas injection straddle system that consists of engineering design, installation and testing, resulting in a two-fold incremental increase in the production rate and costing only one-tenth of recompleting the well. This has increased the chance of success to restore most idle wells with tubing leaks and opens the door to enhance the existing production.
Application of Inflow Tracers to Complement Production Logs in a Carbonate Field
Authors: Urdal J. , Habib M. A. , Mikalsen T. , Chowdhury S. , Cleveland K. O. , Huseby O. , Bergo C. , Pride S.
Published: October 2023

The use of classical production logging tools (PLT) for the purpose of inflow profiling has occurred for decades in the Greater Ekofisk Area (GEA) wells. Recently, several of the newly drilled wells have been completed with inflow tracer (IFT) technology to trial an alternative means of acquiring an inflow profile. The results and lessons learned from employing both methods on the 2/7-S-35 well in the Eldfisk field are shared in this paper.

The IFTs are directly installed on the outside of the reservoir liner adjacent to each sleeve. The initial acid stimulation is key for releasing and displacing the tracers into the reservoir. Upon production start, the tracers are flowed back continuously with the produced fluids and sampled at surface. The samples are analyzed, interpreted, and a continuous inflow profile for the well is generated.

The inflow profiles derived from both IFT and PLT methods revealed differing results in the subject well. The most notable deviation was in the bottom of the well (Hod formation) where the PLT spinner did not show flow while the IFT showed a significant flow contribution (30% of total). Upon closer analysis of the PLT run, the temperature sensor data suggested flow from the bottom of the well which conflicted with the spinner sensor data. Overall, the IFT data and PLT temperature sensor data confirmed flow from the Hod formation which was also consistent with performance from offset analog wells.

Both methods offer an inflow profile solution at a similar cost but come with their own strengths and weaknesses. Careful design and application are recommended to increase the chances of capturing a representative inflow profile for a given well. The novelty of this paper is in the implementation of the patented rate-dependent method for generating IFT-based continuous inflow profiles for the subject well. The IFT provided a more credible inflow profile than the PLT and this data supported the decision to drill a dedicated well to further explore the Hod formation potential in the Eldfisk field.
Risk Analysis on Geological and Geomechanical Uncertainties - Learnings from CO2 Sequestration Modelling of a Saline Aquifer in Central Alberta, Canada
Authors: Wang Xiaoqi , Gillrie Mitchell , Chen Zan , Chen Suzy
Published: October 2023

The Government of Alberta has entered into evaluation agreements with 25 hubs to investigate permanent CO2 sequestration options, including deep saline aquifers. There is a rush of optimistic claims from numerous organizations on how much CO2 they are planning to dispose, yet it remains unclear how this will be achieved. In this study, practical models were constructed for the Basal Cambrian Sandstone (BCS) to evaluate its CO2 storage capacity from regulatory, geological and geomechanical perspectives.

Field data was collected from the Quest carbon capture and sequestration (CCS) facility, operated since 2015. A geomechanics module, integrated with a dual-permeability fluid model, was utilized to investigate the input variables of the storage formation and associated caprock, such as permeability, Young's modulus, Poisson's ratio, and Biot coefficient, etc. Barton-Brandis model was adopted to investigate CO2 leakage paths through natural fractures in the caprock. An extensive history match was performed and forecast cases were conducted to assess CO2 plume migration, trapping mechanisms, and pressure distribution throughout the life span of the project and over one hundred years after shut-in of CO2 injection.

The results have shown that the amount of CO2 disposal could be over four times the original designed capacity if the injection wells can be operated at maximized injection rate while still maintaining injection pressure below the regulated pressure limit. In addition, the CO2 storage potential can be significantly impacted by geological and geomechanical uncertainties, including ambiguities in structural and petrophysical interpretations, characterization of natural fractures, etc. For example, injection pressure that is higher than the minimal effective stress could lead to failure in the caprock. The changes of natural fracture permeabilities are modelled with the effective stress of surrounding rock matrix and the extent of CO2 leakage into the caprock is studied. The results showed that when reactivated, the natural fractures, especially those near the injectors, substantially increased the amount of CO2 leakage into the caprock. When this happens, it could potentially impose a risk to both storage capacity and safe containment of the sequestered CO2. Finally, proxy functions were developed for correlating the calculated CO2 storage capacity and risk factors. This provides a simplified analytical approach for further risk mitigation.

This study performed a comprehensive quantification of regulatory, geological, and geomechanical risks in a CCS project with real-world data. It provides an exemplary workflow of risk assessment, both numerically and analytically, to guide exploration, planning, operations, and monitoring of future CCS projects.
Optimization of Well Diagnostics and Repair
Authors: Yugay A. , Zhukin A. , Vorozhikhin S. , Girgis F. , Alkarbi M. A.
Published: October 2023

Well Integrity discipline is all about barriers. Double barrier envelope policy is a well integrity requirement well-known worldwide. This can be found in international standards: API RP90 (1 & 2), Norsok D10, ISO 16530 (1 & 2). This policy applies to wells with positive pressure at surface capable to flow naturally. Primary barrier envelope consists of well equipment which is in direct contact with produced or injected media. Secondary barrier envelope will be exposed to well media in case of primary barrier element failure. This paper focuses on such kind of wells that have a positive pressure at surface and fall under double barrier policy.

Any failure in primary barrier envelope (means - completion) is easily repairable during workover by simply re-completing the well with new completion. This can be done almost unlimited number of times, as long as there is a place to set the packer. Failure in secondary barrier envelope (means - casing) can be done as well, but not that easy and limited amount of time. In some cases, especially for onshore wells it might be economically more reasonable to drill the new well rather than to deal with complicated workover. Depending on the Company policy, casing integrity can be restored in sections using casing patches or the entire length can renewed by running and cementing casings of smaller diameter. Obviously, in both cases it impacts the size of the completion and cannot be done multiple times.

Once the primary barrier element fails, it will result in sustained annulus pressure (SAP) appearance. SAP wells create a risk of external leak to surface (or subsurface) in case of secondary barrier element, such as wellhead, casings, or different accessories failure.