bluuebunny/crossref_metadata_2025 huggingface dataset:
New High-Frequency Pressure Monitor Algorithm Guided Multistage Stimulation for Long Lateral without Mechanical Isolation
Authors: Zeng Bo , Zhou Nayun , Guo Xingwu , Wang Yiting , Fu Yunlong , Wang Guan , Korkin Roman , Fedorov Andrey , Borisenko Alexey , Luo Yin , Li Haoyan , Zhang Jie
Published: October 2023

Due to the reservoir complexity that includes natural fractures and weak bedding planes, over 30% of China shale gas wells in Sichuan Basin encountered casing deformation issues. Casing deformation resulted in huge challenges for wellbore accessibility and prevented setting of bridge plugs of the subsequent stages at the originally designed depth. To avoid leaving the target lateral unstimulated after casing deformation incidents, operators would have to perforate the entire remaining lateral and conduct multiple fracturing treatments with diversions; however, high uncertainty in such practice risks under-stimulation or overstimulation.

In this study, we share several field cases that utilized high-frequency pressure monitoring (HFPM) to evaluate and improve stimulation effectiveness in wells with casing deformation. The detailed operational procedure and initial findings from comparison between HFPM diagnosis and results from other monitoring techniques, such as seismic monitoring and downhole camera, are also discussed. Observations, limitations, and potential improvements from these cases demonstrate a potentially duplicatable practice for stimulation in wells with casing deformation.
Experimental Studies on Thermal Properties of Different Class G Cement Composites for Geothermal Well Applications
Authors: Abid Khizar , Tellez Miguel L Romero , Teodoriu Catalin
Published: October 2023

The efficiency of geothermal energy depends on the amount of heat gathered at the surface. Therefore, the heat transfer between the working fluid and the formation must be reduced. This can be done by using cement with low thermal conductivity on the upper section of the cement. While on the other hand, high thermal conductive cement should be deployed at the lower section of the well to facilitate heat transfer.

Therefore, the thermal properties of cement become important in the context of geothermal wells. For this reason, thermal conductivity tests were conducted for 305 days on different Class G cement composites. The additives used were Fly Ash, Bentonite and Gilsonite. Moreover, the samples were cured at dry and wet conditions to observe the effect of moisture on thermal conductivity. Whereas the value of thermal conductivity (k) was measured with the help of two separate apparatuses that work on different principles.

It was found that with the addition of additives, the thermal coefficient of the Class G cement was reduced, but more importantly, fresh cement data differs from long-term cured samples, which will have an impact on the overall heat transfer coefficient. It was also observed that the sample's thermal conductivity is a time-dependent property and evolves as the curing time increases and then becomes relatively constant. While the addition of an additive in the class G cement has an impact on the value of k and it was also noted that irrespective of the cement additive or curing time, the thermal conductivity of the cement cured in saturated condition always had a higher thermal conductivity than the samples cured in dry condition.

The novelty of this work is that this study deals with the long-term measurement of the thermal conductivity of different Class G cement composites. Moreover, it also compares the value of k obtained from two different measuring thermal conductivity equipment and discusses the reason for obtaining the different values of k.
Efficient Modeling of Proppant Transport in Multi-Cluster Stages
Authors: Wang J. , Olson J. E.
Published: October 2023

In this study, an Eulerian-Lagrangian (E-L) proppant model was coupled with the simplified three-dimensional displacement discontinuity method (S3D DDM) hydraulic fracture model to simulate proppant transport in multiple simultaneously propagating hydraulic fractures in a stage. The E-L proppant model computes slurry flow in the Eulerian regime and proppant particles in the Lagrangian regime, while the S3D DDM hydraulic fracture model efficiently simulates 3D non-planar hydraulic fracture geometries. Synthetic case studies were conducted to examine the effect of cluster spacing and the number of clusters on proppant placement in multi-cluster stages. Numerical results showed that the tip process zone of the nearby hydraulic fractures significantly reduces the hydraulic fracture width at the affected area, which obstructs the proppant transport in the affected hydraulic fractures. In addition, the non-planar hydraulic fracture plane slows down proppant movement and can potentially cause proppant bridging. The effect of multi-cluster design on proppant transport is mitigated with larger cluster spacings or fewer numbers of clusters in a stage.
Successful Leak Repair and Restoration of Oil Production a West Kuwait Case Study
Authors: Elias M. , Tagarieva L. , Abu-Eida A. , Al-Azmi N. , Patra M. , Al-Sabea S.
Published: October 2023

Two West Kuwait oil wells were completed with initial flowrates of 3,000 and 5,000 stb/d with zero and 25% water cut, respectively. However, water cut increased quickly to 100% for both wells. Therefore, a production logging program was developed to find the source of water flow. Once the source was found a well workover plan was developed. Well intervention was done along with Production Logging to detect the water source and to verify well integrity.

Due to the change in well production from oil to water, the operator requested aid in identifying the cause of the production change. The first step in the process was a production logging run, both flowing and shut-in to prove well flow parameters and to identify the source of the water. This involved logging both the completion of interest, with the ability to log other sections of the upper completion if the water source was not initially found. Once the water sources were located a well remediation plan was developed to re-establish both wells production baseline.

This paper presents the results from two wells, which initially had the same issue: water production from the upper completion. However, the actual results highlight the capability of production logging to identify the root causes of production drop-off. In the first well, the PLT run discovered no water production from the lower zone, but dump flooding from an upper zone that shut off oil production. The upper zone water production was from a corroded completion, repaired with a perf and squeeze shutting off the water flow. The second well could only be logged during shut-in, where the sensor responses were consistent with water ingress, however, the flowing pass had no sensor responses. This was caused by the jetting of the water inflow from casing damage in the formation above the production zone, making sensors' responses invalid. The shut-in pass clearly showed the location of water ingress, from a casing failure in the completion above the production zone resulting in dump flooding and shutting off oil production. The remediation in this instance was a mechanical repair followed by a cement squeeze to isolate the water zone. Production testing and follow-up PLT runs confirmed the elimination of water production and 100% oil production.

This case study shows the power of PLT programs to find water ingress points, even when the inflow is not in the completion zone of interest. This allows the operator to plan remediation programs that results in a return to normal or near normal production levels.
Multilateral Completion Technology to Improve Reservoir Management
Authors: Ameen Yousef , Almasri Abdulrakeeb , Saleh Abdullah , Alkadem Mortada
Published: October 2023

Effective well completion design is crucial to optimize well and field performance, with many operators utilizing different techniques to achieve this important objective. However, the conventional means of designating wells for reservoir monitoring and standalone wells for production presents challenges to cost-effective reservoir management.

Vertical observation wells are usually drilled in different locations to monitor the reservoir and assist with planning and intervention decisions by running periodic logs to obtain subsurface information. However, these wells can be costly and occupy valuable space that could be utilized for production. An alternate technique is to drill a pilot hole, perform all the necessary logging, and obtain the required reservoir information. The pilot hole is then plugged and sidetracked to a producer well. Nevertheless, the collected data only remains valid for a limited period due to potential changes to the reservoir.

The demand for cost-effective, optimized drilling of production and observation wells has led to a paradigm shift in multilateral well technology that achieves both production and monitoring objectives for both laterals at the same time. Using this enhanced technology, wells can be completed with a pilot hole (vertical) drilled for reservoir evaluation throughout the life of the well, with permanent downhole gauges (PDHGs) installed for pressure and temperature monitoring, while the horizontal lateral functions as an oil and gas producer. Combining the observation and producer wells into one well results in cost savings and enhanced reservoir production and surveillance programs. In addition, the capability to access the lateral allows for intervention in both the motherbore and lateral at any time.

Well intervention operations for a well completed with this multilateral technology involve slickline runs to gain access to the horizontal lateral, retrieve an isolation sleeve, and install a tubing exit whipstock (TEW) for lateral re-entry. Later, coiled tubing (CT) or wireline tractor can be run through the window into the lateral to perform the logging and intervention necessary. Upon completion, the TEW is retrieved from the window, the isolation sleeve is reinstalled, and the well is returned to production. Well intervention through such multilateral completion demonstrates the ease and efficiency of accessing both the vertical and horizontal lateral, without requiring a rig or completion retrieval.

This paper will highlight the multilateral completion technology for accessing both laterals, which includes real-time monitoring capabilities that provide more reliable data for optimum well and field performance.
Case Study: An Effective Solution to Operate ESPs in the Severe Erosive Environments of Unconventional Wells in the Permian Basin
Authors: Villarreal Paola Elizabeth Martinez , Morales Diego Armando Marquez , Briceno Argenis Alberto Garces
Published: October 2023

This case study presents the results of implementing nickel coating on the stages of electrical submersible pumps (ESPs) to extend their run lives in unconventional high-flow-rate wells in the Permian Basin.

The ESPs analyzed in this study previously had short run lives of less than 140 days; the failure reason was severe wear in the pump stages and severe erosion of the housings that led to the detachment of part of the string in the hole in some of the cases. The solution implemented involved the research, analysis, testing, and improvement of manufacturing processes of the proper coating and its application on the pump and gas-handling stages to increase their durability and resistance to abrasion and erosion.

This solution was tested and successfully implemented in four unconventional wells producing from the Cline Shale, which is in the eastern part of the Permian Basin. The following are the well conditions: flow rate of 4,000 B/D, pump setting depth of 6,000 ft, 160°F bottomhole temperature, and perforation depths of 7,000 ft. The implementation and results demonstrated the feasibility of the solution that can be potentially implemented in other oil-producing wells in the Permian Basin.

Drawing on real-world experiences and considering various factors, this case study provides valuable insights and recommendations for operators and engineers working with ESPs in challenging erosive environments. It serves as a valuable resource for improving the reliability and lifespan of ESP systems, ultimately contributing to enhancing operational efficiency and reducing downtime due to frequent workover operations because of failures related to the presence of sand.
The Multiple Bedding Planes (BPs) Effect on Fracture Height Propagation: Experimental Study and Field Data Analysis
Authors: Shuai Li , Bo Cai , Dingwei Weng , Chunming He , Xinbin Yi , Haifeng Fu
Published: October 2023

Geological structures such as pre-existence of multiple bedding planes (BPs) significantly influence the hydraulic fracture height propagation in shale gas and shale oil reservoirs. Field engineers have also proved that fracture height is much lower than designed via monitoring such as microseismic and DTS/DAS test.

In this paper, hydraulic fracturing simulation is studied by injecting fluids into a 1m×1m×1m rock-block sample with multiple thin BPs developed at the in-situ stress condition, and during the operation process, acoustic emission (AE) monitoring is used to obtain the fracture propagation events. After the fracturing physical simulation, we cut the rock sample from three different perspectives and take visual observation of the fracture geometry via fluorescence irradiate. Secondly, we carried out series field data analysis such as fracturing curve history matching, flow-back data analysis and production data analysis, aiming to find the correlation between fluids leak-off rate, flow-back salt concentration, fracture height, fracture complexity and the number of BPs.

Results showed that fracture propagation is a competition controlled by stresses and rock BPs. Fracture propagation is generally perpendicular to minimum principal stress while is locally controlled by the rock BPs. It always initial to be vertical fractures near the wellbore area, while as the vertical fracture penetrates the BPs, fracturing fluids would leak into the BPs and form horizontal fractures, lead to slow propagation in height direction and change the final fracture geometry. Fluorescence irradiate also showed fracture propagation can be divided into three modes, directly penetrate the BPs, arrested by the BPs or bifurcate into BPs, and these are mainly depending on the high-angle natural fractures. The results of this study suggest that a significant portion of fracturing fluids could be retained in BPs, which in turn is the reason of fracture height propagation obstruction. In field data analysis, we find that fluids leak-off rate has positive correlations with BPs number, fracture complexity and hydrocarbon production. Flow-back salt concentration (salinity) also has positive correlation with BPs number while has negative correlation with fracture height. Ratio of fluids leak-off and fracture height (Vleak/Hf) or ratio of flow-back salt concentration and fracture height (Cf/Hf) can be used as evaluating indicators for the number of BPs that fracture penetrates through.

Experimental study and field analysis of the BPs effect on fracture height propagation can provide constructive guide for the hydraulic fracturing of BPs developed reservoirs.
Modelling of Partially Miscible, Multiphase Hydrocarbon Mixtures Using a Fugacity-Based Lattice Boltzmann Method
Authors: Soomro Muzammil , Ayala Luis F.
Published: October 2023

A thermodynamically consistent, fugacity-based lattice Boltzmann method (LBM) is used to carry out simulations of multicomponent, multiphase hydrocarbon mixtures. The mixtures are simulated as partially miscible and a multicomponent equation of state (EOS) is incorporated into LBM through the fugacity. Vapor Liquid Equilibrium (VLE) cases and dynamic cases are presented for different hydrocarbon mixtures. The free energy LBM model, applicable to multiphase systems, makes use of a functional of the (Helmholtz) free energy. Traditionally, this free energy has been limited to empirical "double-well" models and very limited use of EOSs. A new approach utilizing component fugacity bypasses the need for a free energy functional. The fugacity provides a link to incorporate multicomponent EOSs into LBM, resulting in an accurate modelling of hydrocarbon mixtures. We use this fugacity-based LBM to carry out VLE simulations for a binary hydrocarbon mixture to generate pressure-composition and temperature-composition plots. Next, we extend VLE simulations to cases of ternary hydrocarbon mixtures. In all cases of VLE, results from LBM are compared with the results obtained from a flash calculation and are shown to be in excellent agreement. This is significant as the LBM has a legacy of thermodynamic inconsistency due to which such agreement is hard to achieve. Next, we simulate far from equilibrium systems by considering the case of spinodal decomposition for a binary mixture. A homogeneous system is observed to decompose into separate phases, consistent with thermodynamic principles, when initialized in the unstable region of the phase envelope. Our results show the fugacity-based LBM to be a highly accurate model for hydrocarbon mixtures when it comes to capturing thermodynamic equilibrium and fluid dynamics. This study presents a comprehensive analysis of multiphase, partially miscible hydrocarbon mixtures using a lattice Boltzmann model which is consistent with thermodynamics and offers predictions in line with accurate equations of state. This opens the door for realistic pore-scale simulations of hydrocarbons which can be upscaled to develop better reservoir simulators.
Embedding Existing Pipelines in Design of CO2 Transportation Networks for Optimal Sequestration Economics
Authors: Nnamdi D. , Moghanloo R. G.
Published: October 2023

This paper presents a method for incorporating existing pipelines into the design of optimal CO2 transportation networks for carbon sequestration projects. The selection of the optimal pipeline transportation network is a crucial aspect of large-scale carbon sequestration projects as it greatly affects the project's economics. The method proposed in this paper aims to address the limitation of existing open-source tools such as SimCCS2.0which are unable to accommodate existing pipelines in techno-economic optimization. With the recent amendment to the 45Q laws, which now offers 70% more tax credits for carbon sequestration than in 2018, energy companies are exploring the possibility of repurposing gas and liquid transportation lines for CO2 transportation to abandoned oil and gas wells for carbon sequestration. This has further reinforced the need for a method that accounts for existing pipelines in sequestration economics.

The proposed method achieves this by representing the pipeline paths on the construction cost graph as zero-cost paths. Additionally, pipeline tie-in locations are fixed by creating exclusion zones that limit inflow edges around the pipeline path. The solution is then obtained by solving for candidate transportation network routes using graph shortest path algorithms. This reformulation of the CO2 source-sink connection flow problem with limiting constraints on existing pipeline flow direction and capacity makes it possible to assess cost reduction associated with different CO2 sources tie-in locations along existing transport pipelines.

The solution was developed using the Python programming language, and small-scale demo test cases have been used to illustrate its effectiveness in four tie-in cases with single pipeline and multiple pipelines that cut across several CO2 source and sink locations. The method has also been applied to the evaluation of a proposed CarbonSAFEII project and the results used to assess optimal pipeline tie-in points for expanded sequestration capacity.

The developed python package is publicly available on GitHub for researchers and economic analysts to use for evaluating large-scale carbon capture, utilization, and storage (CCUS) projects, with the aim of encouraging further development and collaboration.
Advanced Characterization of the Jansz-Io Field Using AI-Assisted NMR Workflows
Authors: Waugh Matthew , Qleibo Meretta , Xingwang Yang , Jain Vikas , Cheong Boon Cheng , Daud Saiful Hakimi
Published: October 2023

The Jansz-Io field is part of the ‘Greater Gorgon’ project, situated approximately 120km offshore the northwest coast in the Northern Carnarvon Basin offshore Western Australia. This study presents a two-part workflow for determining petrophysical and grain-size related properties of the late Jurassic Jansz Sandstone in the Jansz-Io Field. This field contains highly variable clays and cements distributed both vertically and spatially due to bioturbation and diagenetic processes. The relationship between saturation and pore structure, important for reservoir evaluation and modeling, is not well understood. The objective of the study is to use class-based machine learning (CbML) and nuclear magnetic resonance (NMR) pore-to-production workflows to improve the understanding of the reservoir properties. This will also reduce uncertainty in gas initially in place (GIIP) and estimated ultimate recovery (EUR) during static and dynamic modeling workflows.

The first part of the workflow involves applying CbML to determine petrophysical properties. CbML was used to classify well logs into facies based on rock types. The resulting classification was used to determine core-calibrated continuous petrophysical properties in all wells. In the second part, novel NMR pore-to-production workflows were used to determine grainsize related properties. NMR data from 19 wells were normalized against different acquisition technologies, vendors, and conveyances using factor analysis and fluid substitution methods, to determine textural facies, effective porosity/water saturation, and grain-size distribution across the field.

The workflow comprising CbML and NMR pore-to-production methodologies shows how AI/ML can assist alongside conventional workflows to maximize the return on investment of measurement acquisition. The results show that the fluidsubstituted NMR distribution and grain-size distribution by textural facies is integral to understanding the relationship between permeability, porosity, water saturation, and grain size. Insights from this study are being used to update the geological deposition model to reduce uncertainty in GIIP and EUR during static and dynamic modeling workflows.

The integrated workflow enables the determination of continuous core-calibrated properties required for not only petrophysical evaluation but also for geological and reservoir modeling to optimize completions and production. The significance of the study lies in its ability to improve the understanding of reservoir properties and reduce uncertainty in GIIP and EUR, leading to more accurate reservoir modeling and optimized production. The novelty of the study lies in the combination of CbML and NMR pore-to-production methodologies to determine petrophysical and grain-size related properties of the Jansz-Io Field.
Expanding Sweep Volume Effect and Mechanism of Pulse Injection Improving Viscous Fingering
Authors: Chen Xin , Li Yiqiang , Liu Zheyu , Liu Shun, , Trivedi Japan , Liao Haiying
Published: October 2023

Viscous fingering of the injected fluid will significantly reduce the swept volume. Increasing the injected fluid viscosity can impress viscous fingering, but the reservoir and economy limit its application. Exploring a simple, effective, and universal viscous fingering impression method can effectively improve secondary oil recovery efficiency. This paper focuses on the effect and mechanism of pulse injection to expand the swept volume and provides experimental guidance for related pilot applications. Microfluidic and core fluidity experiments were conducted using large-scale glass chip and artificial cores, respectively. Including four constant-velocity and nine pulse microfluidic experiments under four injection rates (40, 1000, 300, and 5000 nL/min), three pulse frequencies (0.1, 1, and 10 Hz), and three pulse amplitudes (0.25, 0.5, and 0.75). Image recognition can quantitatively characterize the expanding swept volume efficiency of pulse injection. The macroscopic effect of pulse injection was verified by core fluidity experiments, and the mechanism of pulse injection expanding the swept volume was given from two aspects of force analysis and invasion front backflow. The results of constant injection experiments show that increasing the injection rate will cause the invasion front to transition from capillary fingering to viscous fingering, but the final swept volume first increases and then decreases. Pulse injection can transform the invasion front morphology from a multi-branched structure to a thicker one- or two-channel structure. Moderate pulse frequency and high pulse amplitude are beneficial to pulse injection to expand the swept volume. When the frequency is 1 Hz (amplitude is 0.5), and the amplitude is 0.75 (frequency is 1Hz), the swept volume can be expanded by 9.38% and 12.51%, respectively. The results of core flooding experiments show that pulse injection can increase water permeability. Pulse injection can generate fluctuation of injection pressure by the periodic change of injection rate, equivalent to inputting additional energy into the injection system. The additional pressure gradient is the fundamental reason for promoting the expanding throat flow and swept volume. Besides, the pulse injection leads to the inhomogeneous backflow of the invasion front, shortening the distance of multiple flow channels and delaying the formation of dominant channels. This work innovatively use low-frequency pulse injection as a universal method to improve viscous fingering and propose the mechanisms of pulse injection improving pore throat flow, which can provide an experimental basis for research in related fields.
Experimental Study of Gas-Liquid Two-Phase Flow in a Vertical Wellbore with Reciprocating Pumping Rod
Authors: Ma Gaoqiang , Han Guoqing , Shi Junfeng , Xiong Chunming , Zhao Ruidong , Zhang Xihsun
Published: October 2023

For the rod lift system, the up-and-down reciprocating motion of the sucker rod continuously exerts external forces on the fluid in the wellbore, which intensifies the instability of the gas-liquid two-phase flow. At the same time, due to the presence of the sucker rod, the cross-section of the flow channel in the wellbore is changed from a circular to a rod-pipe annulus, making the fluid more susceptible to the sucker rod motion. In order to study the effect of the reciprocating motion of the sucker rod on multiphase flow, an experimental platform was built to study the pressure and flow pattern changes in the wellbore under various gas-to-liquid ratio and lifting parameters, e.g., number of strokes, gas and liquid injection rate. Observed from the experiments, four flow patterns under the reciprocating motion of the sucker rod were identified: bubbly, slug, churn, and annulus flow. It is the relative motion between the rod and the fluid that intensifies the gas-liquid slip effect, and the collision fusion between bubbles is more frequent. However, when the gas injection rate exceeds a certain limit, the influence of sucker rod motion gradually decreases and the flow pattern is not changing. This paper further investigated the pressure distribution in the wellbore with different number of stokes and gas/liquid injection rates. The analyses indicated that the pressure at different test points showed periodic changes with time. Meanwhile, the higher the number of stoke, the more pronounced the periodicity of pressure, and the pressure fluctuation is highly associated with the up-and-down motion of the sucker rod, i.e., the number of strokes is proportional to the frequency and amplitude of pressure fluctuation. At the position of rod coupling, the chance of collision and fusion between bubbles increases and air slug are formed. Based on the experiment data, the drift-flux model (DFM) is modified for multiphase flow in the rod lift wellbore. Because the relative motion between the rod/coupling and the fluid, the presented DFM in this paper has higher prediction accuracy at low and high-volume fraction of gas compared with the literature DFM for a vertical wellbore. This mechanism study not only helps to optimize lift parameters to maximize pumping efficiency, but also provides experimental data in developing or verifying mathematical gas-liquid two-phase flow model for the rod lift system.
Surface-Controlled Digital Intelligent Gas Lift Valve Technology Deployed in North American Unconventional Producing Wells. Lessons Learned After Field Trials and the Path Ahead
Authors: Suarez S. A. , Shaw J. , Bastardo R. , Patterson G.
Published: October 2023

Objectives/Scope

Several wells have now recently been completed with a novel digital intelligent surface-controlled gas lift technology with the goal of assessing their performance and their feasibility as an artificial lift solution for producing unconventional wells. These installs mark the first ever successful installations of this technology in North America land. As of recent years, gas lift has started to gain ground as the artificial lift option of choice for the operators in many Unconventional basins and the goal of this research aims to provide the complete details of the lessons learned during these projects and lay the ground for scaling-up in the near future.

Methods, Procedures, Process

The research followed closely actual field trial installations of Surface-controlled intelligent gas lift systems that were installed in the Bakken and Permian Basins with the premise of testing its performance prior to larger deployments. The totality of the field trials featured multiple digital intelligent gas lift mandrels that carry pressure and temperature gauges and electrical-actuated valves controlled from surface through a tubing encapsulated line. This can ensure that the optimum gas injection rate can be selected to achieve the maximum production throughout the life of the well over time as Bottom Hole Pressure declines, without the need for wireline intervention to change out a valve, which is required with conventional gas lift. Tailored well designs applications were done to each well candidate with the purpose to evaluate their behavior and agreed-upon KPI's during the trial period. A project closing document was produced for each well which details all the learnings the team was able to gather from real life testing and experience.

Results, Observations, Conclusions

In these applications, the surface-controlled intelligent gas lift system presents an opportunity for a data driven approach to ensure the optimum gas injection rate is achieved through surface operation and downhole multi-port functionality. While paving the way to other areas where the concept could prove useful as well. We present field unloading procedures, optimization options and well performance enhancements with the newly available data that was able to be gathered. Operational and design improvements were successfully implemented by the team and the operator from the documented lessons.

Novel/Additive Information

First wells successfully installed in the Unconventional plays in the US, proving that the technology can become a nice fit in the operator's toolbox when dealing with rapid changing conditions and steep declines in production rates coupled with higher Gas Liquid Ratios such as unconventional reservoirs.
Lessons Learned and Best Practices from Multiphase Flowmeters Implementations
Authors: Benlizidia Imed , Saeed Mubarak M
Published: October 2023

Several E&P companies capitalize on the capabilities of multiphase flowmeters (MPFMs) and strategically use them as part of their digital transformation requirements. Different types of MPFM technologies have been implemented, operated and utilized for various wells operating conditions. This paper is intended to share the experience gained and the knowledge acquired during MPFM units’ deployments and use.

The approach is a result of extensive engagements with this technology across various stages from setting the requirements for appropriate MPFM technologies honoring large spectrum of field and wells operational conditions and production strategies, screening stages of potential metering techniques, flow loop testing in controlled environment, actual field implementations, approval of technologies for respective applications, and the implantation of adequate maintenance and training programs. Although, every stage is standalone and requires special attention and expertise, every stage complements the other stages and requires full comprehension of the whole ecosystems including but not limited to reservoir and production engineering and facilities and IT infrastructures.

Results have indicated that there are no "one-size-fits-all" multiphase flow metering technology. These technologies do vary in their capabilities, limitations, operational and installation costs, maintenance and best practices to ensure their continuous reliabilities and to meet operators’ expectations (NFOGM Handbook for multiphase metering 2005). In certain applications, the implementation requirements can be simple and inexpensive, yet it can be very complex and relatively costly in other applications. Possessing the necessary knowledge of the nature of the field, production strategies, operational constraints and deep understanding of the technology and its limitations can facilitate effective operation of these technologies to achieve maximum value for the entire asset.

This paper is based on implementation of different MPFM units across various operational oil and gas fields for almost two decades. It shall be used as educational resource for both operators and technology providers and persuader to all stakeholders to extend their collaboration to identify potential improvement opportunities in the existing systems and business models.
Nanobubbles Enhanced Flotation of Oily Produced Water at Large Natural Gas Platform
Authors: Colic M
Published: October 2023

During petroleum extraction at offshore platforms a large amount of so called "produced water" with emulsified oil is created. This manuscript will summarize our efforts from science behind centrifugal nanobubbles enhanced microbubbles flotation to results of the pilot studies on removal of emulsified oil from produced water. Full – scale installation of treatment system at large natural gas platform will then be briefly described. Flotation Systems need treatment chemicals, coagulants, and flocculants for the best oil removal efficiencies. The synergistic application of nanobubbles enhanced flotation with treatment chemicals will be described.
Improved Estimation of Net Pay and Gas to Oil Ratio Using Intuition AI with Limited PVT Data
Authors: Chakraborty R. N. , Elshahawi H. , Raghorte M. , Malik M. , Hanson S. A. , Samano L. , Dasgupta S.
Published: October 2023

Efforts have been ongoing for decades to extract valuable reservoir insights by interpreting the mud-gas logging data in combination with drilling and other petrophysical parameters. Unlike dedicated wireline operations, mudlogging data are readily available during drilling, and if reliable, they can provide an alternate method for assessing fluid properties such as Gas-Oil Ratio (GOR) and reservoir quality indicators such as net pay thus reducing the need for costly wireline operations especially in situations resulting from high pressure, high temperature, wellbore instability, tar, low pay or high angle wells, where wireline operations can be difficult or too expensive to justify. Conventional mud gas interpretation techniques are mostly based on empirical cut-offs and formulae, and unless tuned very locally, these will generally produce unreliable and inaccurate results compared to the pressure-volume-temperature (PVT) measurements. There have been attempts to use machine learning (ML) models to improve accuracy, but these have also had limited success due to the limited size and range of data that is generally available for model training. Such models have inherent difficulty catering to the broad range of fluid property distributions that exist in nature.

Intuition artificial intelligence (AI) is a novel causation AI methodology that iterates experts’ hypotheses and creates a scientific fabric to model system behavior. It has the ability to interpret complex changes in the state of a system by converging multiple views and eliminating hard-to-detect situational fluctuations. Intuition AI was applied to enhance the mudlogging-based reservoir characterization, with highly encouraging results. Importantly, it is able to do so with limited data sets. In our case, based on the data processed from 5 wells containing 15 pay clusters, the estimation of GOR and net pay using intuition AI fell within the 10% deviation range when compared with the ground truth, the PVT results.
An Explainable Artificial Intelligence Model for Top of Cement Identification
Authors: Hou Tianjun , Jan Aymeric , Snovida Zoriana , Blyth Matthew
Published: October 2023

An explainable deep learning artificial intelligence (AI) model has been designed for instantaneous identification of the top of cement (TOC). Identifying TOC is a critical part for evaluating a well cementing operation and detecting unexpected fluid loss, cement contamination, hole enlargement, etc. The model's results are compared with TOC determined by human interpreter via manual review of acoustic waveform data - a time and resource-intensive interpretation technique, highly dependent on individual expertise.

In the AI model described, attention layers are applied to the neural network architecture. When the model outputs the TOC, these layers highlight the zone of interest on the waveform data. This zone indicates the area given higher weight by the model when making its interpretation; it is in effect, the "explanation" given by the model. Thus, the model simultaneously supplies the answer and indicates how it arrived at the answer. Reliability of results can be verified by comparing the zone of interest chosen manually by experts versus the model's selection. Experiments have confirmed a good match between the two.

The AI model was tested on 33 cementing job data collected from field. 26 jobs were used for training and 7 for testing. On the 7 testing jobs, experiment showed an average difference of just 4.7 ft between the TOC manually determined by human interpreters and the model's estimate. It outperforms the neural network architectures without applying attention layers, like CNN and UNET, proving the effectiveness of the attention layers in improving AI model accuracy. The experiment also demonstrated the increased efficiency and reduced cost of TOC identification achieved with the new technique, as it takes at maximum only 3 seconds for determining the TOC for each job. In addition, the zone of interest selected by the model highlights the range where the acoustic waveform changes abruptly along the depth dimension in each job, corresponding to the human interpreters’ cognitive process when determining the TOC. As reported by experts, the showing of the zone of interest makes the model and the results trustworthy, as the "explanation" is reasonable.

The proposed model shed light on making industrial deep learning neural networks explainable. Although neural networks were proposed decades ago, because of their black box nature their implementation is limited in the energy industry, where poor engineering or commercial decisions can have severe financial or HSE consequences. Explainable AI models enable users to understand how AI makes interpretations, whether results are reliable, and when they should take manual control of the AI system.
A Hands-on Introductory Course to Increase Interest in the Petroleum Engineering Workforce: A Case Study
Authors: Enab K. A. , Elmasry Y. O. , Nath F. , Khasawneh M. T. , Pena J. D.
Published: October 2023

This study highlights the benefits of a four-day hands-on course on recruitment of high school students for petroleum engineering programs. This course sought to inform students of different areas in the oil and gas sector, highlight the importance of petroleum engineering in today's efforts toward energy sustainability, and stimulate their interest in petroleum engineering as a potential career direction. The first three days of the course lasted four hours, and the final day lasted two hours. The first day outlined the course's activities, the history of petroleum engineering, reasons for considering petroleum engineering as a career choice, and the available STEM scholarships students can use to support their college studies. The second and third day covered technical content and their application in group based hands-on experimental activities. The fourth day covered the remaining technical content and their application, in addition to a general summary of what was learned throughout the course. Twenty-six students participated in the course, of which 95% were of Hispanic origin and 27% were female. The course, via a pre- and post-survey analysis, proved successful in increasing awareness and interest in petroleum engineering at a critical point when students are trying to determine what career to pursue. Moreover, the results reflect the effectiveness of the course in leveraging their understanding of the oil and gas sector and its importance for future energy sustainability. This course represents a potentially viable approach to bridge STEM education and workforce needs in the U.S oil and gas sector. What follows in this paper is a detailed outline of the course, and its results, for easy replication and future research. The novelty of this study is the use of a pre- and post-survey evaluation method on a course that provides an overview of the three aspects of petroleum engineering.
A Practical Production Solution for Multilateral Horizontal Well in Natural Gas Hydrate: Superposition Principle and Reciprocity
Authors: Ma Tianbi , Chu Hongyang , Li Jiawei , Zhang Jingxuan , Gao Yubao , Zhu Weiyao , Lee W. John
Published: October 2023

Due to high energy density, clean combustion products and abundant resources, natural gas hydrates (NGHs) have been regarded as an important clean energy source with the potential for large-scale development and utilization. However, pilot tests in NGHs show that their production rates are far below commercial needs. Multilateral well technology may lead to a solution to this problem because it can dramatically expand the drainage area of production wells. This paper presents a practical production model for multilateral horizontal wells in NGHs. In developing our solution to the diffusivity equation to model this process, we applied the superposition principle and reciprocity. We wrote the governing equation in cylindrical coordinates to describe the natural gas hydrate flow process. We used moving boundaries and dissociation coefficients to model the solid-to-gas transition process in hydrates. We used Laplace transforms and the Stehfest numerical inversion method to obtain solutions for flow in hydrate reservoirs. We applied the superposition principle and Gaussian elimination to obtain the desired solution for multilateral horizontal wells. We validated our proposed model with a commercial numerical simulator. We also performed sensitivity analyses to determine the effects on production behavior of the number of branches, dissociation coefficient, radius of the region with dissociated hydrate, and dispersion ratio. We used properties from the Nankai Trough as inputs in a case study we conducted.
A Novel Method to Measure the Phase Behavior of Black Oils: Saturation Pressure and Liquid-Vapor Fractions
Authors: Ahitan S. , Abedini A. , Latorre T. , Wanat E. , Li Z. , Velasquez M. , Alboudwarej H. , Burger J. , Ungar F. , Yang T.
Published: October 2023

Building a robust PVT model critically relies on accurate phase behavior data which has been traditionally obtained using PVT cells. While the PVT cell can provide accurate data, it requires a large volume of downhole or recombined samples which are usually expensive to collect. A novel microfluidic chip design and method is presented in this work to rapidly measure bubble point and liquid-vapor volume fractions of black oil systems at multiple pressures and temperatures. The chip was initially charged with a representative single-phase live oil at a reservoir temperature. Afterward, the pressure was lowered to subsequent pressure steps to measure the saturation pressure, and liquid and vapor volumes. The waiting time at each pressure step was adjusted to ensure that the equilibrium condition was achieved. The aforementioned procedure was performed at multiple temperatures to measure corresponding saturation pressures and L-V fractions, ultimately generating a partial phase envelope of the test oil sample. The measurements were conducted for various oil samples with a wide range of API gravity. The high-resolution optical access along with an in-house developed automated image analysis algorithm were used to detect the saturation pressures and quantify the L-V fractions. The saturation pressures for each of the tested crude oils were compared with those obtained from conventional Constant Composition Expansion method, showing a tight agreement between the data (i.e., within less than 5% deviation). The measured microfluidic L-V fractions of each sample are also in strong agreement with those obtained by conventional methods, where available. Given the very small volume of oil sample, easier control on operating parameters, and faster run-time and analysis time required for this microfluidic approach, the phase envelope of a testing oil can be determined in a day. The microfluidic platform developed in this work can be an alternative approach to some of the conventional PVT tests with an order of magnitude higher lab throughput. This makes PVT data accessible by reducing cost, and sample size requirements, and potentially moves the energy industry to a data-on-demand model. With a much smaller physical size inherent to microfluidic devices, this platform can be deployed to operations sites, alleviating the sample handling and shipment challenges that industry currently struggles with.