bluuebunny/crossref_metadata_2025_split huggingface dataset:
Accuracy and Uncertainty Evaluation of Measuring the ISO Long-Term Conductivity of Proppants
Authors: Vysotskiy Roman , Makashova Galina , Radaev Vladimir , Yudin Alexey 
Published: September 2021

Abstract
One of the critical factors in planning a hydraulic fracturing treatment is proppant selection. Conductivity is an important property for ensuring efficient reservoir stimulation. Conductivity data obtained during laboratory measurements help determine which proppant to use. ISO provides standard testing procedures and methodology for measuring the long-term conductivity of proppants but does not document expected measuring uncertainty. This paper addresses accuracy and uncertainty estimation of ISO 13503-5 conductivity measurements.
For the purposes of this study, three proppant samples were used. Two identical samples of high-strength ceramic proppant (HSP) and one sample of natural silica sand were distributed among six laboratories that participated in this study. The resulting data from measuring conductivity and permeability of the samples were used to calculate repeatability and reproducibility in terms of standard deviations in accordance with ISO 5725-2. Uncertainty of measuring the ISO long-term conductivity of proppants was calculated in accordance with ISO 21748.
The evaluation shows that conductivity and permeability values of ceramic proppant and natural sand measured by the ISO 13503-5 method have quite high interlaboratory uncertainty. Uncertainty of conductivity is from 19 to 100% depending on closure stress for values of conductivity from 3000 to 200 md-ft respectively. Uncertainty of long-term conductivity measurements increases dramatically while conductivity decreases. At the same time, internal evaluation of uncertainty in measuring conductivity within one laboratory resulted in approximately 15% as reference value of uncertainty for a single laboratory and never exceeded 30% in given conductivity range.
ISO 13503-5 prescribes testing procedures; however, it does not provide information about measurement uncertainty. This information is essential for comparing different proppants to enable reasonable selection criteria for a job, to identify proppant property inconsistency and quality decline over time due to changes in production process or raw material, or to resolve discrepancies in different laboratory measurements. Uncertainty values were estimated for a wide range of conductivity data and different proppant types.
Model-Free Assessment of Inter-Well Connectivity in CO2 WAG Projects Using Statistical Recurrent Unit Models
Authors: Chen Hongquan , Sen Deepthi , Datta-Gupta Akhil , Nagao Masahiro 
Published: September 2021

Abstract
Routine well-wise injection and production measurements contain significant information on subsurface structure and properties. Data-driven technology that interprets surface data into subsurface structure or properties can assist operators in making informed decisions by providing a better understanding of field assets. Our machine-learning framework is built on the statistical recurrent unit (SRU) model and interprets well-based injection/production data into inter-well connectivity without relying on a geologic model. We test it on synthetic and field-scale CO2 EOR projects utilizing the water-alternating-gas (WAG) process.
SRU is a special type of recurrent neural network (RNN) that allows for better characterization of temporal trends, by learning various statistics of the input at different time scales. In our application, the complete states (injection rate, pressure and cumulative injection) at injectors and pressure states at producers are fed to SRU as the input and the phase rates at producers are treated as the output. Once the SRU is trained and validated, it is then used to assess the connectivity of each injector to any producer using permutation variable importance method, wherein inputs corresponding to an injector are shuffled and the increase in prediction error at a given producer is recorded as the importance (connectivity metric) of the injector to the producer. This method is tested in both synthetic and field-scale cases.
The validation of the proposed data-driven inter-well connectivity assessment is performed using synthetic data from simulation models where inter-well connectivity can be easily measured using the streamline-based flux allocation. The SRU model is shown to offer excellent prediction performance on the synthetic case. Despite significant measurement noise and frequent well shut-ins imposed in the field-scale case, the SRU model offers good prediction accuracy, the overall relative error of the phase production rates at most producers ranges from 10% to 30%. It is shown that the dominant connections identified by the data-driven method and streamline method are in close agreement. This significantly improves confidence in our data-driven procedure.
The novelty of this work is that it is purely data-driven method and can directly interpret routine surface measurements to intuitive subsurface knowledge. Furthermore, the streamline-based validation procedure provides physics-based backing to the results obtained from data analytics. The study results in a reliable and efficient data analytics framework that is well-suited for large field applications.
An Extended Viscoelastic Model for Predicting Polymer Apparent Viscosity at Different Shear Rates
Authors: Zeynalli Mursal , W. Al-Shalabi Emad , AlAmeri Waleed 
Published: September 2021

Abstract
Polymer flooding is one of the most commonly used chemical EOR methods. Conventionally, this technique was believed to improve macroscopic sweep efficiency by sweeping only bypassed oil. Nevertheless, recently it has been found that polymers exhibiting viscoelastic behavior in the porous medium can also improve microscopic displacement efficiency resulting in higher additional oil recovery. Therefore, an accurate prediction of the complex rheological response of polymers is crucial to obtain a proper estimation of incremental oil to polymer flooding. In this paper, a novel viscoelastic model is proposed to comprehensively analyze the polymer rheological behavior in porous media.
The proposed viscoelastic model is considered an extension of the unified apparent viscosity model provided in the literature and is termed as extended unified viscosity model (E-UVM). The main advantage of the proposed model is its ability to capture the polymer mechanical degradation at ultimate shear rates primarily observed near wellbores. Furthermore, the fitting parameters used in the model were correlated to rock and polymer properties, significantly reducing the need for time-consuming coreflooding tests for future polymer screening works. Moreover, the extended viscoelastic model was implemented in MATLAB Reservoir Simulation Toolbox (MRST) and verified against the original shear model existing in the simulator. It was found that implementing the viscosity model in MRST might be more accurate and practical than the original method. In addition, the comparison between various viscosity models proposed earlier and E-UVM in the reservoir simulator revealed that the latter model could yield more reliable oil recovery predictions since it accommodates the mechanical degradation of polymers. This study presents a novel viscoelastic model that is more comprehensive and representative as opposed to other models in the literature.
Utilizing Novel Expandable Steel Packers to Overcome Multi-Stage Fracturing Completion Deployment Challenges in Horizontal Gas Wells
Authors: Ombe Ebikebena M. , Gomez Ernesto G. , Syamsudhuha Aldia , AlKwiter Abdullah M. 
Published: September 2021

Abstract
This paper discusses the successful deployment of Multi-stage Fracturing (MSF) completions, composed of novel expandable steel packers, in high pressure, high temperature (HP/HT) horizontal gas wells. The 5-7/8" horizontal sections of these wells were drilled in high pressure, high temperature gas bearing formations. There were also washed-outs & high "dog-legs" along their wellbores, due to constant geo-steering required to keep the laterals within the hydrocarbon bearing zones. These factors introduced challenges to deploying the conventional MSF completion in these laterals. Due to the delicate nature of their packer elastomers and their susceptibility to degradation at high temperature, these conventional MSF completions could not be run in such hostile down-hole conditions without the risk of damage or getting stuck off-bottom.
This paper describes the deployment of a novel expandable steel packer MSF completion in these tough down-hole conditions. These expandable steel packers could overcome the challenges mentioned above due to the following unique features:
High temperature durability.
Enhanced ruggedness which gave them the ability to be rotated & reciprocated during without risk of damage. Reduced packer outer diameter (OD) of 5.500" as compared to the 5.625" OD of conventional elastomer MSF packers. Enhanced flexibility which enabled them to be deployed in wellbores with high dog-leg severity (DLS).
With the ability to rotate & reciprocate them while running-in-hole (RIH), coupled with their higher annular clearance & tolerance of high temperature, the expandable steel packers were key to overcoming the risk of damaging or getting stuck with the MSF completion while RIH. Also, due to the higher setting pressure of the expandable steel packers when compared to conventional elastomer packers, there was a reduced risk of prematurely setting the packers if high circulating pressure were encountered during deployment. Another notable advantage of these expandable packers is that they provided an optimization opportunity to reduce the number of packers required in the MSF completion. In a conventional MSF completion, two elastomer packers are usually required to ensure optimum zonal isolation between each MSF stage. However, due to their superior sealing capability, only one expandable steel packer is required to ensure good inter-stage isolation. This greatly reduces the number of packers required in the MSF completion, thereby reducing its stiffness & ultimately reducing the probability of getting stuck while RIH.
The results of using these expandable steel packers is the successful deployment of the MSF completions in these harsh down-hole conditions, elimination of non-productive time associated with stuck or damaged MSF completion as well as the safe & cost-effective completion in these critical horizontal gas wells.
Intelligent Approach for GOSP Oil Recovery Enhancement
Authors: AlDogail Ala , Gajbhiye Rahul , AlNaser Mustafa , AlNajim Abdullatif 
Published: September 2021

Abstract
This study aims to propose an intelligent operational advisory solution that guides the plant operation team to optimal HPPT/LPPT pressure settings that compensate for the variation in ambient temperature effect to maximize plant revenue. Traditional industry practice is to operate a gas-oil-separation-plant (GOSP) at fixed operating conditions ignoring the variation in the ambient temperature (Ta) leading to a loss in oil recovery and associated revenue. The variation of ambient temperature (Ta) highly affects the separation process, where ambient temperature varies greatly from summer to winter.
To develop a correlation, a GOSP model was constructed by OmegaLand dynamic simulator using a typical Saudi Aramco GOSP design. Oil recovery values were determined by running the process simulation for a typical range of high-pressure production trap (HPPT), low-pressure production trap (LPPT), and ambient temperature (Ta). Then, an intelligent approach was built to determine the optimum pressure of LPPT and HPPT units for each ambient temperature condition using an artificial intelligence technique.
Results show that liquid recovery decreases with an increase in ambient temperature at constant HPPT and LPPT pressures, indicating adjustment in HPPT or LPPT pressure responding to the temperature variations can improve the oil recovery. At constant LPPT pressure and ambient temperature, the oil recovery increases with an increase in HPPT pressure until it reaches the optimum value and then decreases with further increase in the HPPTpressure suggesting that there is an optimum HPPT pressure at which oil recovery is maximum. At fixed ambient temperature and fixed HPPT pressure, liquid recovery increases with increasing LPPT pressure until it reaches the optimum value, and then it decreases with further increase in the LPPT pressure suggesting that there is an optimum LPPT pressure at which oil recovery is maximum.
Integrating Sustainability into Material Management Practices
Authors: Maggioni Bruno , Giliberti Francesca , Panunzio Emanuele 
Published: September 2021

Abstract
Modern Society followed, and it is still largely following, a linear process for natural resources utilization: raw material extraction, goods manufacturing, use/consumption, waste generation. Such a model is proven to be not sustainable because it cannot go forever considering the limited quantity of available resources on Earth but also because of waste and process by-product management.
A multitude of diverse initiatives to change this process started at different levels and within several industries in the last years including the O&G sector. Most of these initiatives share the same principle of "regeneration": waste and materials represent, in this view, the "feedback loop" able to make the production process a circular process, instead of an open-end one.
Eni promotes and supports different initiatives to implement the principles of a Circular Economy and the objective of this paper is to describe a process implemented within Eni aimed at reducing the footprint of the Oil and Gas Industry with reference to material usage. Surplus and damaged materials are no more treated as waste, but they are re-engineered or re-conditioned (if necessary) in order to be redeployed to other projects within Eni affiliates all around the world. Nowadays this process is well structured and formalized within Eni and it is extensively applied involving all worldwide affiliates, reducing the overall CO2 footprint.
Results achieved within Eni, in the last few years, averages between 6,500 and 17,500 ton of steel of material redeployed among Eni's affiliates for a value ranging between 26 and 71 million USD. The overall average result is 23,000 CO2 equivalent ton not released per year and 242,000 GJ of energy saved (ref. to steel manufacturing estimated impact:1.9 ton di CO2/ton steel cast and 20 GJ/ton steel cast).
Extending this process to involve material and equipment manufacturers, it is possible to improve the whole supply process reducing at the "source" the material storage needs, the material surplus and the produced wastes, including the CO2 emission produced in the transport phase. Initiatives like "Just in Time" delivery and material "Buy Back", mainly applied in Countries where Framework Agreements are already in place between Eni and its manufacturers and where manufacturers have their production sites and other facilities, are essential to achieve this target. Eventually, applying the approach to the whole supply chain and operations management will allow to reduce the "last mile" warehousing and transportation needs, including the dimension and capability of the operations fleet.
Breaking Through the Boundary: Are HVFR and Landing Target The Solution? A Charlie Lake Exploitation Strategy
Authors: Mombourquette Cole , Erickson Dave , Geldreich Tim , Ross Mark , Hudson Eric , Cammaert Dan 
Published: September 2021

Abstract
The objective of this exploitation strategy was to evaluate fracture-driven interactions (FDI) between intervals within the Braeburn members of the Lower Charlie Lake formation. With the primary goal to determine if a single well can be drilled in the Middle Braeburn and effectively drain reserves from two previously distinct producing intervals. The target intervals in this study were separated by a boundary layer composed of interbedded anhydrite, siltstone, and dolomite layers.
Wells were completed in sequence using cemented ball-drop fracturing, and high-viscosity friction reducer (HVFR) fluid systems. Diagnostics including pressure monitoring, fracture modelling, and tracers were employed to evaluate stimulation response between wells. Realtime downhole pressure monitors observed the non-producing upper wellbore, while the lower well produced. Fluid rheology determined viscosity changes for different HVFR loadings, and fracture modelling assessed the impact of anhydrite on fracture height at different fluid viscosities. Proppant tracers injected in the lower well were logged in both wellbores observing propped communication between layers. Fluid and pressure diagnostics were used to monitor effective drainage between wells over time.
During completion of the lower well, two (2) notable pressure communication events were observed in the offsetting upper well. Following the logging applications performed on both wellbores the results displayed three (3) localized points along the offsetting lateral. At which, a propped communication event was observed within a one (1) meter radius of investigation from the offsetting wellbore. The heel-most propped communication event in the offsetting wellbore was correlated to one of two (2) observed pressure communication events. The two (2) other instances of propped communication did not correspond with an observed pressure event. Following the logging application, the lower well was flowed back and put onto production. During this production period, the upper well remained shut in. Subsequent fluid diagnostic responses have indicated an increasing FDI response, facilitating the flow of hydrocarbon from the upper to the lower wellbore. This communication was primarily observed near the heel of both wellbores. Based on the results of the diagnostic tracers, the fracture model was updated to provide a development tool that would be more predictive for fracture height growth around thin anhydrites in the Charlie Lake formation.
The technique of fracture stimulation through the anhydrite layer can be used to reduce the total number of wells required to effectively drain the formation.
Rock Heterogeneity Effects on Fluid Diversion During Stimulation Treatment
Authors: Sibarani Tiurma Theresa , Ziauddin Murtaza 
Published: September 2021

Abstract
Rock heterogeneities, such as variations in pore distribution, pore throat diameter, and initial permeability, significantly affect the outcome of carbonate matrix stimulation treatments. A better understanding of the influence of these parameters on stimulation and diversion, especially for the performance of self-diverting acids, is needed for efficient stimulation designs.
Carbonate rock samples from six outcrop formations, with permeability ranging from 2 to 150 md, were used in the study. Large blocks were acquired for each outcrop, and several 1.5×6-in. core plugs were drilled from these blocks. Pore structure in each outcrop was characterized by high-pressure mercury injection (HPMI) porosimetry and flowing fraction measured with nondestructive tracer tests. Pore volume to breakthrough (PVbt) for a viscoelastic self-diverting (VES) acid was determined at 150°F for injection rates ranging from 1 to 10 cm3/min. The diversion ability for the VES acid was evaluated by (1) the increase in pressure during VES acid injection and (2) the pore volumes this higher pressure was maintained.
The results show that flowing fractions measured by injection of either KCl (potassium chloride) tracer in deionized water or a dilute polymer solution is an effective means for characterizing the pore structure and for predicting the pore volume to breakthrough and diversion performance of VES acids. High-permeability grainstones such as Indiana Limestone, where most of the rock porosity is accessible to aqueous fluids (high flowing fraction), have the largest pore volume to breakthrough and the largest relative pressure buildup during injection of VES acids. Low-permeability rocks with heterogeneous porosity (low flowing fraction) have lower pore volume to breakthrough and had a relatively low-pressure build-up. The results are summarized in a master-curve, which facilitates prediction of pore volume to breakthrough of VES acids from rock properties that can be measured by non-destructive techniques. Correlations for PVbt and the diversion ability of the VES acid are presented, so that the performance of these acid systems can be estimated for formation rocks where direct measuremets of PVbt or diversion are not be practical.
Value of DTS in Multi-Stacked Reservoirs to Better Understand Injectivity and Water Flood Effectiveness – A Field Example from the UAE
Authors: Gomes Jorge , Mason Jane , Edmonstone Graham 
Published: September 2021

This paper highlights the application of downhole fiber optic (FO) distributed temperature sensing (DTS) measurements for well and reservoir management applications: 1) Wellbore water injectivity profiling. 2) Mapping of injection water movement in an underlying reservoir.
The U.A.E. field in question is an elongated anticline containing several stacked carbonate oil bearing reservoirs (Figure 1). Reservoir A, where two DTS monitored, peripheral horizontal water injectors (Y-1 and Y-2) were drilled, is less developed and tighter than the immediately underlying, more prolific Reservoir B with 40 years of oil production and water injection history.
Reservoirs A and B are of Lower Cretaceous age, limestone fabrics made up of several 4th order cycles, subdivided by several thin intra dense, 2-5 ft thick stylolitic intervals within the reservoir zones. Between Reservoir A and Reservoir B there is a dense limestone interval (30-50 ft), referred as dense layer in the Figure 1 well sections.