bluuebunny/crossref_metadata_2025 huggingface dataset:
Numerical Simulation Study on Enhanced Efficiency of Geological CO2 Storage with Nanoparticle
Authors: Kumasaka J. , Sugai Y. , Ishibashi F.
Published: February 2024

Carbon dioxide (CO2) geological storage has a large potential to achieve a net-zero target of CO2 emissions. CO2 injected into the storage formation typically becomes a super-critical state under the underground temperature and pressure conditions. The injected super-critical CO2 (scCO2) tends to migrate upwards within the reservoir due to its lower density compared to the formation brine even though the density of scCO2 is quite higher than that of gaseous phase CO2. Moreover, injected CO2 is affected by not only the gravity segregation but also the viscous fingering. These phenomena are expected to cause poor storage efficiency in carbon storage projects. In this study, we investigated the potential of adding common metal oxide nanoparticles to scCO2 to improve the storage efficiency utilizing the properties of scCO2 as a solvent under subsurface conditions.

This paper presents the pseudo-fluid modeling of scCO2 containing nanoparticles and the results of numerical simulation considering the effects of nanoparticle types and concentrations on the CO2 storage efficiency. In particular, the effect of density alteration on CO2 storage efficiency was investigated in this study. Some pseudo-fluid models of scCO2 containing four types of nanoparticles, such as aluminum oxide, silicon dioxide, titanium oxide, and zinc oxide with different concentration were created, respectively. Furthermore, numerical simulations of scCO2 injection with and without nanoparticles were performed using a two-dimensional radially symmetric model. The results from this work showed the migration of CO2 to the upper part of the formation was suppressed and the storage of CO2 in the lower part of the formation was promoted when scCO2 was injected with nanoparticles. Furthermore, CO2 breakthrough time was delayed several months or years and total breakthrough quantities were also decreased as the density and concentration of nanoparticles in scCO2 became higher in the case of installing an imaginary production well for pressure control. These results suggest that the injection of nanoparticle-dispersed CO2 improves the storage efficiency of CO2 geological storage compared to the injection of CO2 alone. Furthermore, this study showed that the concept has possibility of improving the safety of CO2 geological storage, which may play an important role when considering the long-term CO2 sequestration as well.
Optimization of Injection Scheme for China's First Carbon Storage Project in Offshore Deep Saline Aquifer
Authors: Wang Zhiqiang , Li Hangyu , Liu Shuyang , Liu Junrong , Xu Jianchun , Chen Jiayu
Published: February 2024

Carbon capture and storage (CCS) is one potential way to mitigate the CO2 emission to atmosphere and achieve the goal the carbon neutrality all over the world. Enping 15-1 CO2 Geological Sequestration Project is China's first offshore CCS project. The injection schemes including injection well type and gas injection rate are investigated in this work. A compositional & geomechanical simulator (CMG-GEM) is applied to establish a pseudo field-scale model and design the schemes for the project. The results show that the evolution of CO2 saturation of vertical well and horizontal well are almost consistent during the injection and post-injection period, but the horizontal well has lower BHP, which is safer and could prevent the formation fracturing. In addition, the scheme of increased gas injection rate is optimal when horizontal well is used for the project as the lower BHP and more capillary trapping CO2. Therefore, the scheme of horizontal well with increased gas injection rate is recommended for the project.
Experimental Investigation of Oil Displacement Caused by Fracturing Fluid Imbibition in Hydraulically Fractured Oil-Wet Shale Reservoirs
Authors: Jian Zhu , Fei Wang , Li Liu , Jiaxin Wang , Dong Xiong , Zhuo Dong , Herun Bi , Shicheng Zhang
Published: February 2024

Spontaneous imbibition (SI) has proven to be an effective method for enhancing oil recovery in water-wet shale reservoirs due to the capillary force. There are few articles that focus on the water imbibition and oil displacement for oil-wet reservoirs. However, we believe that the potential of oil displacement caused by water imbibition should not be neglected, since field observations from dozens of wells show strong positive relevance between initial oil production and post-fracturing well shut-in time in the oil-wet shale oil reservoir of Junggar Basin, China. In this paper, several experiments and numerical simulations are designed to shed light on the mechanism of oil displacement by fracturing fluid imbibition, including the driving force and the oil recovery of different pores. The real field fracturing fluid which is prepared by guar gel, anti-emulsifiers, anti-swelling, cleanup additives and gel breakers is used as the test fluid. Also, the oil-wet shale cores saturated with crude oil are used as the samples. Firstly, contact angle after different contact times and interfacial tension are measured to figure out the petrophysical properties of fracturing fluid and crude oil. Secondly, the SI experiments using the fracturing fluid made up of deuterium oxide as the imbibed fluid are conducted to discover the oil recovery of different sizes of pores with shale samples. The low-field nuclear magnetic resonance(LF-NMR) is used to describe the relative content of crude oil under different pores and different SI times. Finally, an experimental core model is established based on the above experimental results. The results show that wettability alteration appears in the oil-wet the core sample. As the contact time increases, the contact angle decreases continuously. The interfacial tension decreases from 72(water and crude oil) mN/m to 1.2(fracturing fluid and crude oil) mN/m. These two phenomena effectively explain the driving force of imbibition and displacement in oil-wet samples. The imbibition oil recovery is about 18.4% in the oil-wet core samples, which indicates that oil-wet cores have a certain oil displacement effect. The fracturing fluid enters the mesopore first because of the driving force produced by wettability alteration and the low frictional resistance, and the imbibition oil recovery in the mesopore is 35%, which is higher than that in micropore and small mesopore in oil-wet samples. This phenomenon and result show a sharp contrast with that of water-wet rock cores proved by previous studies. Finally, a new capillary force curve accounting for the effect of wettability alteration is fitted to characterize the oil displacement in oil-wet samples by the experimental core model simulation. This study aims to demonstrate the SI characteristics of oil-wet shale and helps to provide crucial theoretical foundations for developing oil-wet shale reservoirs.
Complexities in the Characterization and Index Measurements of the Unconventional Qusaiba Rock Member from Qassim Region, Saudi Arabia
Authors: Gramajo E. , Rached R. M. , Ghreizy A. E. , Maalouf E. , Ayranci K.
Published: February 2024

Unconventional shale reservoirs, notably Saudi Arabia's Qusaiba member, store a significant portion of the world's natural gas and tight oil reserves. The understanding and successful extraction of these reserves require a detailed comprehension of their complex geological, petrophysical, and geomechanical properties.

This research addresses the challenges faced during sample preparation and testing of standard rock mechanical properties of a shallow subsurface core from the Qalibah Formation (Sharawra and Qusaiba members), of the Qassim region in Central Saudi Arabia. Traditional methods faced limitations due to the shale's intricate heterogeneity, layered structure, and unique formation processes. However, microindentation testing helped solve most of these challenges.

With its expansive sampling capability, this method provided insights into the rock's strength and elasticity. By comparing the results of the micro-indentation tests against conventional measures, this study highlights the potential of innovative techniques in characterizing unconventional shale reservoirs, offering a promising avenue for future exploration and understanding.
The Design of Green Molecules for Demulsification
Authors: Ekoue-Kovi K. , Jakubowski W.
Published: February 2024

New chemistries are needed to address the negative environmental impact of currently used demulsifier (DMO) formulations especially when used offshore to separate water from crude oil emulsions. The goal of the study was to synthesize new eco-friendly molecules with targeted environmental profile, which behave as DMOs and develop a better understanding of chemical structure – biodegradation and toxicity relationships.

Different synthetic pathways were employed to assess the possibility of synthesizing molecules with specific biodegradation kinetics, acceptable toxicity as well as high demulsification performance. In the design of new DMO, we used highly biodegradable molecules as one of the building blocks of the final polymer. New DMO polymer biodegradability in seawater was evaluated by following the OECD guideline 306, and toxicity was tested against saltwater algae by measuring EC50 in 72 hours. The performance of the green DMO intermediates was tested in several crude oils in upstream and downstream applications using bottle test procedure and electrical desalting dehydration apparatus respectively.

New molecules demonstrated > 60% biodegradability in 60 days and >10 mg/L toxicity to seawater algae. Synthesized DMO intermediates showed higher biodegradation profiles compared to currently used DMOs, which are based on alkoxylated alcohols, phenolic resins and diepoxides that are not biodegradable due to high molecular weight and strong C-C and C-O-C bonds in their chemical structure. The connections of the newly synthesized highly biodegradable molecules were achieved with the bonds, which are prone to hydrolysis. In addition, the created polymer was functionalized with hydrophobic building blocks to tune the final DMO performance. The results showed that these new molecules were able to separate water from crude oil emulsions and showed optimal and similar performance to some of the currently used non-biodegradable DMO intermediates. The performance of new DMOs was strongly dependent on their chemical structure and composition. Clear correlations of relative solubility number to chemical structure and performance were observed.

Synthesized polymers exhibited a better biodegradation profile and better competitive performance to conventional non-biodegradable DMO products especially in terms of water drop during the bottle test evaluation. Due to systematic design of the synthesized polymers, this research led to a better understanding of chemical structure – biodegradation and toxicity relationships as well as performance of new DMO molecules.
Comparative Study of CO2 Mineral Trapping: A Numerical Investigation
Authors: Mouallem Johny , Arif Muhammad , Raza Arshad , Mahmoud Mohamed
Published: February 2024

During CO2 geo-storage, mineral dissolution is considered as the safest trapping technique but the longest and the most complicated as it includes different mechanisms: geo-chemical reactions, chemical reactions and physical mechanisms like diffusion and advection. Many factors also influence the mineral trapping capacity of the geological formation like mineralogy, temperature, pH, CO2 fugacity, pressure of CO2 and salinity of the brine. The scope of this study is to compare the mineral trapping of CO2 of sandstone and carbonate formations using a numerical simulation approach as a function of temperature, salinity and mineralogy of the subsurface systems.

Numerical simulation will be performed in this study using the geo-chemical, multi-component, non-isothermal, and multi-phase simulator CMG-GEM. 2D models will be used to study the mechanisms occurring during mineral trapping and how they affect its efficiency. Sensitivity analysis will be performed on the effect of temperature, mineralogy and brine salinity on CO2 mineralization tendency for both geological formations at the same conditions. The mineral composition, porosity and storage capacity will also be evaluated. It was found that dissolution and precipitation of minerals occurred during and post CO2 injection. The presence of small quantity of illite tends to decrease immensely the trapping capacity of CO2. Moreover, temperature and salinity tends to promote the mineral activity during CO2 storage.

This paper thus provides new insights into the dynamics of CO2 storage by mineral trapping pertinent to sandstones and carbonates. Furthermore, it will help in site selection evaluation for carbon geo-sequestration (CGS) projects. Extensive study of the parameters affecting the mineral trapping will be presented.
In Situ Characterization of Wettability in CO2-Brine-Rock System Based on X-Ray Microtomography
Authors: Chen Qian , Hou Jian , Wei Bei , Xue Yu , Du Qingjun , Liu Yongge
Published: February 2024

It is of great significance to evaluate wettability accurately because it controls the fluid distribution in the pores and throats. And the wettability is directly related to the safety of CO2 sequestration in aquifers. In this paper, in situ characterization of reservoir wettability based on micro-CT is investigated due to its repeatability and convenience. At first, a CT scanner is used to obtain the fluid distribution. Then, we use the artificial intelligence wizard segmentation method (AIWSM) to segment the images. The AIWSM combines threshold segmentation method with deep learning segmentation method to improve segmentation accuracy. After that, we measure CO2 contact angles and contact surface area between CO2 phase and rock phase to evaluate reservoir wettability, respectively. The measurements consider the influence of the roughness of the reservoir rock surface, which can better reflect the real situation of the reservoir. At last, we also study the influence of wettability on CO2 residual trapping. The results indicate that the images segmented by AIWSM is more accurate for each phase in CO2-brine-rock system. Subsequently, we consider the influence of salinity and surfactant concentration on CO2 contact angles and contact surface area between CO2 phase and rock phase. It shows that when salinity increases from 10,000 mg/L to 100,000 mg/L, CO2 contact angles decrease from 124.55° to 116.32° and contact surface area between CO2 phase and rock phase increases from 7.44×107 μm2 to 12.03×107 μm2 gradually. In addition, when surfactant concentration increases from 0 wt% to 0.5 wt%, CO2 contact angles increase from 124.55° to 137.88° and contact surface area between CO2 phase and rock phase decreases form 7.44×107 μm2 to 3.03×107 μm2 gradually. The results obtained by two wettability characterization methods are consistent: the reservoir hydrophilicity is weakened with the increase of salinity and enhanced with the increase of surfactant concentration. After we accurately characterize the reservoir wettability in situ, the influence of wettability on CO2 residual trapping can also be obtained. It shows that the more hydrophilic the rock is, the higher the CO2 residual trapping efficiency is. Accurate characterization of wettability in CO2-brine-rock system is essential for the long-term safety of CO2 sequestration. This can help better select the suitable CO2 sequestration locations for aquifers and provide reliable experimental data for CO2 sequestration simulation.
Changing The Status Quo: First Application of Utilizing Novel Tracer Technology for Monitoring Hydraulic Fracture Stage Contribution
Authors: Arshad W. , Brohi I. , Pooniwala S.
Published: February 2024

The ultimate goal of drilling and stimulating long horizontals wells is maximizing production with minimal economic investment to ensure a good return on investment. The costs associated with fracturing and stimulation are a significant portion of a well's completion cost. Considering that the number of stages and stage volumes have an almost linear relation with well completion costs, on a field scale optimizing the number of stages and fracturing treatments can have massive impact in budget optimizations.

Conventionally stage contribution in the field is estimated by running a PLT post fracturing. In long horizontals accessibility to TD could pose a challenge. Running a PLT also requires a wellbore cleared of isolation frac plugs or ball seats based on the completion type. In sub-hydrostatic pressured reservoirs, the debris created from the milling of plugs can be detrimental to the ultimate well performance. The results from PLTs’ provide a snapshot of well performance at a single point of time and not the dynamic response of the well over time.

In order to overcome the challenges of conventional PLTs’ for fracture stage contribution monitoring, various technologies were evaluated. It was decided to implement chemical tracers as an alternative monitoring technology due to the ease of deployment and some well monitoring benefits. The chemical tracer technology provides an intervention-less method to qualitatively measure stage by stage production which can be used to enable building a production profile for each stimulated stage. As the results can be observed with a quick turn-around time, production trends can be easily monitored over time by implementing a structured well surveillance plan.

Chemical tracers are applicable to Open Hole Multi-Stage Fracturing (OH-MSF) completions using ball operated frac sleeves and openhole packers and the "Perf & Plug" method of multi-stage fracturing in cemented completions. The examples presented in this paper include a 5-stage OH-MSF and 11-stage P&P stimulation scenarios.

Post-fracturing flowback in conjunction with chemical tracers provide interesting insights into the well clean-up operations and stage contributions from the heel to the toe of the well. Quite a few succinct conclusions can be made on the behavior of reservoirs and some unusual observations which highlight the persisting weaknesses in understanding complex reservoirs. The lessons learnt from some of the observations may help optimize the future hydraulic fracturing and post fracturing well clean-up strategy in the field.

This paper discusses the workflow of selecting the appropriate tracer technology, setting success criteria, and the field implementation of the technology.
Conveyance Options for Pipe Recovery in a Stuck Drill Pipe Scenario in Horizontal Wells
Authors: Kishore S. , Woods J. , Engel D. , Batyrkhanov K.
Published: February 2024

Recovery of stuck drill pipe is a challenge in deep horizontal wells. Typically, in a vertical or slightly deviated well, after attempts have been made for recovery of stuck drill pipe by working the pipe, the option to convey the pipe recovery tools with electric line is relatively simple due to gravity descent. However, in horizontal wells, the options to convey the recovery tools require electric line using tractor or pump-down techniques; alternatively, coiled tubing can be used for conveyance. Our study evaluates these three methods and compares the efficiency and effectiveness of these conveyance methodologies.

The application of these solutions each have their own advantages and some disadvantages, especially as the access within the drill pipe can be limited due to the presence of various types of restrictions such as debris or the variable diameter inside the pipe, which usually has an "internal upset" on the connections. These restrictions combined with the potential nonexistence of circulation will affect the maximum reach for the conveyance methods to differing degrees. The ability to reach the target may be limited in extended reach wells and the target cutting depth may not be feasible with some conveyance options. The presence of radioactive sources in the drilling assembly may also complicate the pipe recovery operation.

Three different conveyance options to perform the pipe recovery operation used on different operations in the Middle East are documented: e-line tractor, e-line pump-down, and coiled tubing conveyance. We compare the options and evaluate the results from the three conveyance methods for the pipe recovery tools to sever the stuck drill pipe. Each of the methodologies can be effective, and the ideal application depends on the existing downhole conditions present at the point the drill pipe becomes stuck.
Multivariate Sensitivity Analysis and Real-Time Algorithms in Data-Driven Coiled Tubing Cleanouts Turn Insights into Action
Authors: Tardy Philippe , Kotlyar Lev , Keong Azwan Hadi , Fonseca Santiago Hassig , Ramondenc Pierre , Segura Jordi , Spesivtsev Pavel
Published: February 2024

Depleted wells require underbalanced coiled tubing cleanouts (CTCO) in which natural production from the reservoir assists solids transport. Reservoir pressures are often uncertain in these subhydrostatic environments, making CTCO design conditions difficult to predict. Under these conditions, sustaining an efficient cleanout is challenging, and risks include undesired leakoff, damage to the wellbore, and stuck pipe. New physics-based algorithms and workflows consume real-time data and output actionable feedback to optimize design, execution, and evaluation of CTCOs.

A coiled tubing hydraulics (CTH) simulator with state-of-the-art flow and transport models improves CTCO design capabilities by sensitizing over every parameter, which generates a combinatorial number of scenarios. Once executed, this multivariate sensitivity analysis generates a large database of sensitized scenarios which delineate a safe and effective operational envelope. Meanwhile, a real-time execution advisor selects the sensitivity analysis scenario that best approximates actual conditions and guides coiled tubing (CT) operators to choose optimal liquid rates, nitrogen rates, and CT speed. This execution advisor is supported by an early inference algorithm (EIA), which assesses reservoir pressure during the run in hole (RIH), while surface testing flowmetering data are consumed by an annular velocity algorithm (AVA) to estimate solids transport efficiency, reservoir leakoff, and inflow in real time. EIA, AVA, and execution advisor run in real time to reduce operation time by up to 15% and nitrified fluid consumption by 10%, ultimately increasing hydrocarbon production by 50%. In addition to driving efficient workflows, the model reduces the risks of poor solids sweeping, formation damage due to reservoir leakoff, solids inflow from reservoir due to large drawdowns, and damage to the surface equipment.

This study demonstrates that by combining extensive multivariate sensitivity analysis, advanced flow models, surface and downhole measurements with real-time interpretation and inference algorithms, CTCO operators can quickly assess multiple metrics of job performance, such as downhole solids sweeping efficiency, reservoir leakoff and inflow, and drawdown, and react accordingly to significantly improve operational outcomes. This first use of these real-time execution advisors paves the way to a step change in the efficiency and safety of CT interventions worldwide.
Case Study: Automated Recommendations to Increase Run Life of the Electrical Submersible Pumps (ESPs) Using Machine Learning
Authors: Silvia Shejuti
Published: February 2024

Unplanned ESP shutdowns and failures result in deferred production, which can lead to significant revenue losses. Most operators rely on engineers to optimize hundreds of ESPs using traditional surveillance technologies. Due to inherent limitations of these technologies, identifying critical conditions and taking remedial actions is extremely time consuming. This case study demonstrates how automated field production solutions (AFPS) has helped a major operator in North America to increase ESP run life in two of its producing assets.

AFPS is an ensemble of machine learning (ML) and physics-based models that predicts critical conditions, estimates remaining useful life (RUL) and provides remedial recommendations to increase run-life of the ESP. ML models for predicting critical conditions were trained using historical timeseries sensor data, hand labeled by experts for various clinical conditions. Physics based models for detecting critical conditions were calibrated using well completions, fluid property, inflow performance, power, and correlations data. Recommendations models were trained using 5 years of event action logs data for 500+ ESPs installations in North America.

In this study, we demonstrate how AFPS increased run life of an ESP with gas interference and locking conditions. Since the first few months of run life, ESP1 experienced sudden fluctuation in motor current, and increase in intake pressure and motor temperature. Its production declined to outside of the minimum recommended flow range. AFPS was able to accurately identify these critical conditions and estimated reduced remaining life. Between May to Sept. 2023, ESP1 experienced severe gas interference/gas locking symptoms. AFPS automated recommendation was enabled and implemented with expert supervision. In Aug. 2023, experts carried out three recommendations provided by AFPS, which significantly improved the gas interference condition and reduced excessive cycling due to motor underload and high motor temperature.

AFPS is an innovative approach that combines ML and physics-based methods to automatically provide effective recommendations to increase ESP run-life. Unlike traditional surveillance approaches, AFPS leverages ML models to learn patterns in historical ESP operational data to reliably predict critical conditions, optimal remedial actions and remaining useful life. Thus, AFPS is scalable and robust to different operating conditions and requires minimal human interventions to avoid unplanned shutdowns and failures, resulting in deferred production.
Unlocking Commingled Production Using Geochemical Production Allocation
Authors: Mejia S. , Markano N. , Marquez L. , Bonfanti B. , Cortez O. , Paladines A. , Fernandez E. , Piñeiros S. , Alba E. , Mendoza M. , Molina E. , Reyes J.
Published: February 2024

In Ecuador commingled production is being used as a strategy to fulfill the government's objective of increasing production. A key challenge in commingled production is how efficiently quantify the contribution of individual reservoirs to support production allocation to the zones meeting the regulation requirement. Geochemical fingerprinting is a fast, viable, and cost-efficient method for production back-allocation. The application has been successfully applied and technically validated for the first time in Ecuador, opening a vast business opportunity.

The feasibility, testing and implementation in a major field is covered in this paper. The geochemical allocation method compares the oil fluid composition of representative samples acquired from each reservoir (end members). The method seeks sufficient compositional information at zone level to calculate the zone contributions from the commingled well production composition. This analysis requires high-resolution gas chromatography and geochemistry interpretation, supported by a specialized software.

A production allocation feasibility study was conducted initially to define if end members collected from seven reservoirs in 17 fields could be differentiated in mixtures based on a chemical distance analysis. The chemical distance analysis shows that oils from some reservoirs are very distinctive, while others are very similar, indistinguishable from each other. One advantage is that the sensitivity of the geochemical analysis allows the differentiation of even the very similar oils in mixtures, enabling the calculation of end-member contributions.

Production was back-allocated in the commingled wells and was compared with the results obtained by traditional production logging tool (PLT) measurements in a cross-validated case study. The technology was successfully validated against traditional approaches such as PLT. The outstanding results show 2% difference between the technologies, which resulted in the approval by the client and raised the interest of the Ecuadorian regulation entity to use this technology as a complementary tool of the traditional technologies.

The cost of the proposed alternative represents about 5% of the frequently used methods price. Therefore, all the existing commingled wells in the oilfield are frequently monitored using geochemical production allocation without impacting the oil production. Commingled production has maximized the field value by increasing production revenue while optimizing costs.
Virtual Flow Metering as an Emerging Flow Measurement Technology
Authors: Gryzlov A. , Arsalan M.
Published: February 2024

The accurate measurement of multiphase rates of produced oil, water and gas has always been a significant challenge to the oil and gas industry. Over the last few decades the traditional approach driven by the use of test separators has gradually been replaced by multiphase flow meters, which offer continuous monitoring of multiphase rates in real-time, without separating phases. Currently, there are multiple technologies available on the market, but multiphase flow meters generally are incapable to handle all ranges of fluid properties and operating conditions with satisfactory accuracy in addition to being expensive to purchase and maintain. The last point has motivated the oil and gas industry to seek other alternative metering technologies. In particular, the emergence of cheap sensors and their widespread installation in production systems has led to an exponential increase in data availability obtained from a well. These data combined with a dedicated mathematical algorithm can facilitate the extraction of actionable information relevant to multiphase flow rates. This methodology, which is also known as a Virtual Flow Metering (VFM), is a promising tool which is capable to mitigate the disadvantages of conventional multiphase flow metering and provides the functionality which was not previously available, such as an estimation of downhole flow rates. The objective of this review paper is to outline the current challenges within multiphase flow measurements and to introduce the most promising digital techniques, which have the potential to become a digital successor of a multiphase flow meters.
Assessing the Performance of Thermally Active Polymer as an In-Depth Conformance Technology in a Mature Waterflooded Reservoir: A Recent Field-Scale Case Study Utilizing Interwell Tracers in Argentina's Largest Oil Producing Field
Authors: Kazempour Mahdi , Santamaria Rodrigo , Lizarazo Leonel , Gomez Javier , Iuliano Alberto , Martinez Christian , Fernandez Diego Damian
Published: February 2024

Waterflooding has been a widely practiced method globally for numerous years, and it has been proven in the field to effectively enhance oil recovery in oil-bearing reservoirs, surpassing primary production methods. Despite its considerable potential for boosting oil recovery, waterflooding faces several challenges that can impede its performance, including reservoir heterogeneities, reservoir structural complexities, and unfavorable mobility ratios. Over the past five years, an extensive multidisciplinary effort has been undertaken to address these waterflood challenges and enhance waterflood sweep efficiency in Argentina. As a result, a cutting-edge conformance technology called Thermally Active Polymer (TAP), also known as BrightWater®, has been successfully implemented in Cerro Dragon, one of Argentina's largest oil-producing fields, yielding encouraging outcomes.

To assess the efficacy of TAP as a reservoir-triggered conformance agent, two sets of interwell tracer tests (IWTT) were conducted: one before TAP injection and another after TAP injection when an oil response was detected. These IWTTs represented the first instance of flow pattern change identification within the targeted segment of the reservoir. Additionally, they enabled the quantification of transit time changes subsequent to the in-depth conformance treatment. The study also revealed the establishment of new communication paths while the previously existing paths became less active following TAP placement.

The results obtained from the IWTT tests aligned remarkably well with the expectations derived from conceptual numerical modeling. Furthermore, a distinct correlation was observed between the changes in sweeping profiles observed through tracers and the oil and water production responses on the production side. This confirmed that the thermally active polymer reduced the flow capacities of thief zones, thereby allowing previously unswept segments of the reservoir to come into greater contact with the injected water.

The findings of this study hold significant implications for the effective execution and design of in-depth conformance treatment programs. Moreover, the study equips end users with quantitative tools for more detailed post-monitoring performance evaluation. TAP has emerged as one of the most widely practiced in-depth conformance technologies for both onshore and offshore applications due to its short execution times, small treatment slug sizes, and ease of injection under various reservoir conditions.
Application of a Bayesian Ensemble Algorithm for Automated Production Diagnostic of Gas Wells with Plunger-Lift
Authors: Pan Y. , Bi R. , Yang S. , Lyu Z. , Ju X.
Published: February 2024

Remotely monitoring plunger lift systems enables operators to streamline the cycling of the motor valve in response to plunger arrival at the wellhead, line pressures, liquid levels or pressure differentials. Man-hours and the need for routine in-person field visits to manually fine-tune the plunger system have been diminished. However, identifying the underperforming plunger lift wells with the underlying issues requires application-specific domain knowledge. Continuously monitoring and diagnosing the anomalies and failures in a large data stream is time-consuming, the critical decision-making may be interfered or delayed with inconsistent interpretations during various case analyses. This study presents a Bayesian ensemble time-series decomposition algorithm for continuously deriving the nonlinear dynamics of plunger lift operations (detecting the abrupt change, periodic change and trend) and further facilitating the identification of corresponding root causes.

As a Bayesian ensemble algorithm, it quantifies the importance of each pre-defined time-series decomposition model, leveraging all the models via the Bayesian average. The online surveillance data from gas wells equipped with plunger-lift is assessed with expert diagnoses, and the time span of taking the recommended action is recorded and compared with ensemble predictions. The unforeseen benefits of using the proposed algorithm are carried out when the correct diagnoses have been consistently discerned such that a considerable number of similar wells can be analyzed and identified in far less time. We demonstrate the applicability and efficacy of the method in such kind by showcasing several plunger lift anomaly case studies such as liquid loading, tubing rupture, stuck motor valve, line pressure increase, etc.

The successful applications suggest that the proposed ensemble algorithm is one of the key components of automated production diagnostic of plunger lift gas wells. It leads to fast delivery to operators for dynamically tracking plunger lift anomalies and rapidly taking actions for field-wise optimization. The outcomes are threefold: 1) The interpretation of anomalies is identified and validated using four case studies with credible uncertainty measures; 2) Typical plunger lift abnormal signatures are correctly identified and conform to expert diagnoses; 3) Problem troubleshooting is guaranteed in consistency and requires far less time than manpower with domain knowledge.
Deep Learning Applications for Well Log Correlation
Authors: Fu J. , Li R. , Gao T. , Zhang P. , Wang C.
Published: February 2024

This paper presents a novel approach to well-log correlation analysis, leveraging the capabilities of autoencoders within a deep learning framework. We explore the application of both single and dual-log data inputs to autoencoders, aiming to enhance the correlation analysis of geological layers in oil and gas exploration. Our methodology involved the utilization of Log ASCII Standard (LAS) files, containing various log types, such as Gamma Ray from Resistivity (GRR), Resistivity Deep (RD), Bulk Density (ZDEN), and Compensated Neutron Porosity Sandstone (CNC). The research was conducted across two datasets, each presenting different combinations of these logs.

Key findings demonstrate that while single-log autoencoder models provide valuable insights, the integration of dual-log data offers a valuable alternative in scenarios where the most suitable log type for a particular geographical context is unknown. Furthermore, we present a comparative analysis of the correlation accuracy between different log types and their combinations. This analysis highlights the importance of log selection based on geological context and underscores the variability in performance among different logs.

In summary, our research contributes to the field of geological analysis by proposing an autoencoder-based approach that effectively utilizes the power of multiple well-log data types. This methodology not only streamlines the well-log correlation process, but also provides geological insights for geoscientists. They can utilize both single-log and dual-log data inputs to enhance the accuracy, depth, and richness of geological interpretations in oil and gas exploration.
First Long-Term Polymer Injectivity (LTPI) Test in Magwa Field Targeting Medium Quality Formation in Wara, Great Burgan Field
Authors: Al-Qattan Abrar , Al-Murayri Mohammed , Almahmid Narjas , Alkhuzam Sara , Sanaseeri Abbas , Alajmi Naser , Hassan Abrahim , Kakade Shweta , Banerjee Anirban , Mascagnini Carlos , Adrianov Alexey
Published: February 2024

The Greater Burgan field Kuwait is the second largest oil field in the world and the largest sandstone field. Greater Burgan is divided into Ahmadi, Magwa, and Burgan fields. This paper describes the result of the first Long Term Polymer Injecticity Test (LTPIT) in Magwa field targeting wara reservoir with inferior rock quality comparing with the previous LTPI tests implemented in Burgan Field. These multiple LTPI tests located in different areas of the Greater Burgan Field are aimed to de-risk fast-tracked phased commercial polymer-flooding deployment in pursuit of production acceleration, reserves growth and cost optimization.

An existing water injector in Magwa field was selected and connected to existing effluent water plant. Down-hole pressure and temperature gauges were installed for real-time surveillance monitoring of the pilot operation. Effluent water was treated at specific criteria and then mixed with the dry polymer to form the mother solution. This solution was diluted with treated water to achieve targeted injected polymer solution viscosity. Water-polymer solutions were injected using a high pressure non-shearing reciprocating pump. Injection rates, polymer concentration and viscosity were continuously monitored along with pressure and temperature. Samples from nearby producers to detect polymer breakthrough and measure polymer concentration were collected. A commercial simulation package CMG STARS™ was utilized for numerical simulation evaluation.

Pre-selected sulfonated polymer was used to evaluate injectivity in medium quality zone at multiple rates and multiple polymer concentrations under sub-fracturing conditions. The rate and concentration for full-field application were determined. Target viscosity in-situ (4.7 cp) was achieved at lower concentration (1600 ppm). BHP pressure response to different injection rate and concentration was established. Polymer injection has the potential to improve conformance and establish more uniform zonal intake of injected fluids. The results show overall good polymer injectivity under matrix condition, however, dynamic modeling results incorporating pilot test data does not provide a cost-effective development strategy when compared to other parts of greater Burgan field.

The result of the Long-Term Polymer injectivity test will be further integrated to design the polymer phase development in Greater Burgan Field, de-risking the commercial polymer flood development and therefore to save cost, time, and accelerate production in Wara reservoir.
Attention-Based Bi-Directional Gated Recurrent Unit (Bi-GRU) for Sequence Shale Gas Production Forecasting
Authors: Fargalla Mandella Ali M. , Yan Wei , Wu Tao
Published: February 2024

This paper presents an innovative application of an Attention-Based Bi-directional Gated Recurrent Unit (Bi-GRU) network for predicting shale gas production. Traditional machine learning models applied to gas production prediction often struggle to capture the complexity of the production process and accurately model temporal dependencies in the data. The proposed model addresses these limitations by integrating an attention mechanism into a Bi-GRU framework. The attention mechanism assigns relative importance to each time step in the input sequence, focusing on the most influential factors that drive shale gas production over time. Consequently, our model effectively learns long-term dependencies and identifies critical features in the historical data, thereby enhancing prediction accuracy. Furthermore, the bidirectional nature of the Bi-GRU enables the proposed model to consider both past and future time step information in the prediction process, leading to a comprehensive understanding of the sequence data. The results demonstrated the performance of the proposed model on a significant shale gas production dataset, showcasing substantial improvements in prediction accuracy over conventional machine learning and deep learning hybrid-based models. The findings of this study underscore the potential of the Attention-Based Bi-GRU model as a powerful tool for predictive modeling in the domain of energy production.
A Data-Infused Methodology for Estimating Swelling Potential in Shales Exposed to Various Completion Fluids
Authors: Khan Mohammad Rasheed , Tariq Zeeshan , Murtaza Mobeen , Yan Bicheng , Kamal Muhammad Shahzad , Mahmoud Mohamed , Abbasi Asiya
Published: February 2024

Formation damage in reservoirs poses a recurring challenge throughout the phases of drilling, completion, and production, significantly impeding efficiency and diminishing resource extraction in oil and gas development. This detrimentally affects production capacity, leading to potential reservoir shutdowns and hindering the timely discovery and development of oil and gas fields. The water-based drilling fluids are mixed with various swelling inhibitors; nevertheless, shale swelling could still take place during the completion phase as these fluids do not usually consider this phenomenon. To quantify the swelling inhibition potential of drilling/completion fluids, several laboratory experiments are usually carried out. These experiments are costly, time-consuming, and tedious. This study used machine learning technique to predict the dynamic linear swelling of shale wafers treated with different types of completion fluids containing varying inorganic salts such as NaBr, CaBr2, and NH4Q.

A comprehensive experimental investigation was conducted to gather datasets suitable for training machine learning model based on various completion fluid constituents. The study involved utilizing a dynamic linear swell meter to quantify swelling inhibition potentials, assessing sodium bentonite clay wafers' responses to all completion fluid solutions through linear swell tests lasting 24 to 48 hours. Additionally, the study measured zeta potential and conductivities across solutions with different concentrations. Leveraging sequential data and memory cell architectures, the research developed an LSTM (Long Short-Term Memory) machine learning model aimed at predicting and comprehending swelling behaviors within specific contexts. This model was trained using input parameters such as zeta potential, salt conductivity, salt concentrations, density, and elapsed time, while the model output represented dynamic linear swelling in percentage.

This intelligent technique can be used to guide and streamline laboratory experiments to determine dynamic linear swelling of shales. It can serve as a quick tool to guide fluid engineers at the rig site to delineate shale swelling reasons pre-, post-, and during completion operations. Consequently, operators will be better prepared to deal with unknown swelling issues that lead to NPT in operations.
Integrated Engineering Approach to Drill a Complex Horizontal Well with Stringent Requirements Dictated: A Case Study from Offshore North West Java, Indonesia
Authors: Yuda Bintang K. , Ridhanta I Nyoman , Sany M. Fajar , Kurniawan Aris , Adi Bayu Arie Punto
Published: February 2024

The objective of this paper is to present a directional drilling approach and the technical solution used to overcome directional challenges during landing horizontal section in Carbonate Baturaja of Offshore North West Java. The main directional challenge is the limited directional space to be able landing with 85-degree inclination +/- 3'TVD inside Top Carbonate Baturaja formation since the target landing coordinate is pretty much close to the platform. The precision in hitting landing point is very critical, firstly because there is a high possibility trajectory become a "hook" considering the lateral section is only 20’ TVD below the top Baturaja. The other well requirements/conditions also make directional work even more challenging such as collision issue at the surface interval, the ability to kick off in very soft formation, the uncertainty of Top Baturaja that affect space for directional work from kick-off to landing, and space tangent section for ESP placement to prevent ESP failure during production.

The integrated directional approach starts from the preparation phase during initiating the feasible trajectory and conducts pre-rig move work such as enhancing data survey quality of the offset well, choosing the best available surface slot, selecting a type of trajectory including the option of negative section trajectory (Pregnant Lady) to add more space for directional and the necessary of the pilot hole, and then conduct the assessment for some worse case scenarios based on challenges. The next step is more to BHA tool selections to enhance the success ratio and give more versatility if the worst-case scenarios happened including developing a landing strategy decision tree. The last step is monitoring strategy during the execution and live updating the directional plan based on actual progress and doing the replan to ensure landing as per plan. Geo-steering was implemented while drilling in the horizontal section for accurate well placement into the very thin Carbonate Baturaja reservoir (+/- 30-50 ft TVD) which is also known as total loss circulation formation.

The implementation of this integrated directional approach requires good coordination among the team involved in achieving technical excellence. In the execution phase, by adhering to the project management process developed including the decision tree and the mitigations, ZUG-X was successfully constructed to hit the landing point as per target without inducing any safety incident and related Non-Productive Time (NPT). Moreover, this became the first negative section well drilled in a horizontal well in North West Java and could be implemented in the future.