bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling of Production Decline Caused by Fines Migration in Deep Water Reservoirs
Authors: Tan Yunhui , Li Yan , Wu Ruiting , Rijken Peggy , Zaki Karim , Karazincir Oya , Williams Wade , Wang Bin 
Published: October 2017

Abstract
Many deep water wells experience steep productivity declines. Some field observations indicate that this decline is partly attributed to fines migration effects. This paper presents a numerical workflow to simulate the effect of flow induced fines migration on production decline over time in deep water reservoirs. A permeability reduction function is extracted from long-term core flood tests and implemented into a reservoir simulator. Using the permeability reduction function, production degradation caused by fines migration is simulated in a detailed single well model. From previous research, it is understood that fines migration won't start until the flow velocity is greater than the critical velocity. Through many long-term core flood tests (extended fines migration test), we conclude that the permeability damage induced by fines migration is a function of the pore volume throughput. To address these observations the numerical model is updated such that the interstitial flow velocity is tracked in each individual cell. When the interstitial velocity is greater than the critical velocity, the cell's permeability follows the permeability reduction trend obtained from laboratory data. If the flow direction is reversed, fines migration damage will be recovered. A detailed 3D model is constructed to study the fines migration effect in each part of the wellbore (perforation, fracture etc.) and reservoir. As expected, fines migration starts near the perforation where flow velocity is highest. Depending on the permeability decline rate, the production asymptotes to a constant value after a certain period of time. Both the decline rate and the ultimate residual permeability have a strong effect on the final production. Sensitivities were run to study the effect of fines migration in different completions. As the author's understanding this is the first time that laboratory-based fines migration data is incorporated into a reservoir simulator to predict the production decline using experiment-based fines migration functions. This workflow will help reservoir engineers to predict the damage caused by fines migration, predict production decline and plan remediation.
The Successful Application of Customized Fluids System to Effectively Bridge Across Extreme Overbalance Conditions – Case Histories from Saudi Arabian Field.
Authors: Maley Iain , Jadhav Prakash , Everhard Ian L. , Addagalla Ajay , Hassan Mohammad Omran , Kosandar Balraj 
Published: October 2017

Abstract
Drilling lateral re-entry gas wells in the Eastern Province of Saudi Arabia has become a serious challenge with casing string design limitations leading to excessive overbalance pressures of over 5,450 psi across highly permeable Carbonate (Limestone and Dolomite) formations. The challenges associated with drilling these re-entry build up sections are as below -
Salt water influxes through the Jilh formations Expected severe losses across Khuff A and B formations High density fluid management issues with losses and influx situations Differential sticking across low pressure formations Wellbore instability across the overlying Sudhair reactive shale High angle section profiles (&gt; 60° inclination).
A customized fluid system was designed to overcome the above challenges associated with high overbalance pressure, targeting improved bridging, minimizing pore pressure transmission and increasing wellbore strengthening with increased hoop stress techniques.
Software modelling and permeability plugging tests were performed to evaluate the fluid behavior under downhole conditions and to simulate the characteristics of induced micro fractures. Porosity, permeability and the likelihood of micro fracturing were considered to optimize the bridging mechanism and materials. These results identified a synthetic deformable sealing polymer combined with sized synthetic graphite and ground marble which showed considerable improvement in minimizing spurt and overall filtrate loss with minimum effect on the rheological parameters and stability of the fluid system.
This paper describes the customized drilling fluids performance in two study wells as compared to offset wells. A comprehensive engineered approach addressed the challenges of drilling in such extreme overbalance conditions by using a revolutionary bridging technology. The lessons learned on these wells have been incorporated while drilling subsequent wells to continue to improve performance.
Innovative Solutions to Creating an Accelerated Training & Development Program for Technical Field Personnel
Authors: Robert Seth , Fiffick William , Guillory Robert 
Published: October 2017

Abstract
The following case study details how a major equipment manufacturer accelerated the training and development of new field service technicians. As the drilling industry recovers from a significant downturn, many companies are challenged to devise better programs to quickly train and develop employee competency so that the increased skill demands can be satisfied.
In 2014, an accelerated program was developed, providing training and development that would normally take over a year, and reducing that timeframe to less than six months. The three-phased approach included formal classroom training, field based training, along with mentoring and coaching. Leveraging the existing competence assurance management system, a custom program was developed to cover 3 distinct product lines. Training was not only technically based, but was also included soft skills training such as customer service training, safety training, and mentoring from Senior Management.
The resulting accelerated program was executed for three groups of field technicians, each graduating within the prescribed six month timeframe. Each delegate achieved the targeted competency level of at least 2.1 (on a scale of 1.0 – 4.3). Management was able to reinforce the safety culture and core mission of the organization to each of these employees throughout the program. The company was able to track trainee progress, manage, and successfully coach the delegates throughout the program. Training focused on real world scenarios, helping Field Service Technicians to practice the use of various resources and tools available to learn better troubleshooting skills.
As the oilfield recovers from one of the largest downturns in history, the ability to successfully attract, train and retain qualified technicians will be crucial. Organizations that can successfully manage accelerated development programs will realize benefits in reducing training time, improving standardization and job quality, as well as a modeling of a better safety culture.
Using Data Analytics on Dimensionless Numbers to Predict the Ultimate Recovery Factors for Different Drive Mechanisms of Gulf of Mexico Oil Fields
Authors: Talluru Gowtham , Wu Xingru 
Published: October 2017

Abstract
The ultimate recovery factor is strongly affected by petrophysical parameters, engineering data, structures, and drive mechanisms. The knowledge of the recovery factor is needed for multiple decision makings and it should be known in the whole development process. This study is to estimate the recovery factor from a different perspective with traditional methods.
Using development data from the Gulf of Mexico, this study explores parametric relationships between different reservoirs using data analytics. Given that there are hundreds of attributes to characterize a reservoir, and some of the records in a database may not be accurate or contradictory to each other, we use dimensionless parameters to categorize reservoirs based on similarity theorems. Using dimensionless parameters not only reduces the number of variables for data analytics, but they have physical meanings which make them easily applicable to different scenarios. This research presents a comparative study of different data mining techniques and statistical significance of various geological, reservoir and engineering parameters.
This dataset consists of 4000 oil reservoirs and each reservoir has 82 attributes. Initial data cleaning was carried out on this dataset to remove reservoirs with erroneous data entries. Dimensionless reservoir parameters are defined and used for the study to make the models consistent to other reservoirs. In the model development, 80% dataset was used to train the model and the rest dataset was used to evaluate the trained models. A few models based on their intrinsic design predicted the ultimate recovery factor with an error of 8-9%, and a few other models predicted the same with an error of 10-12%. Ensemble of a few models predicted oil recovery factor with an error of 6%. In addition to predict ultimate recovery factor, relative importance of various dimensionless parameters, and sensitivity of ultimate recovery factor to reservoir and engineering parameters were studied. This kind of study uses already available reservoir data and model to provide a quick means to evaluate new oil reservoirs even with limited data.
A New Approach to Harness Data for Measuring Invisible Lost Time in Drilling Operations
Authors: Lakhanpal Vikrant , Samuel Robello 
Published: October 2017

Abstract
Drilling operations can include invisible lost time (ILT), within productive time and nonproductive time (NPT). ILT is the time lost because a portion of the drilling operation is not performed at maximum efficiency. Current industry techniques use subjective decision making to calculate NPT, which only illustrates that ILT is present and does not address the root cause.
By considering the dynamic downhole conditions and comparing the time necessary for various personnel to perform the same operations, a threshold time can be calculated for each operation, which is used to calculate NPT.
After NPT is calculated, the real-time drilling data are converted to segmented drill-time data [i.e., the time necessary for each activity (Δt)] to convert to a time-series analysis problem. The algorithm developed decomposes the obtained time series into its intrinsic mode functions (IMFs) using the ensemble empirical mode decomposition (EMD), which tolerates residual noise in the signal. Mode mixing is a significant issue when the drilling data are converted into a time-series problem. Hence, an energy conservation principle is presented to identify and help eliminate the false mode components; thereby, only the components that truly represent the drilling activities are used for further calculations. The true characteristic IMFs are then combined with their weights to obtain a modified Δt series, which represents ILT. The weight estimation process is performed automatically to maximize the kurtosis and entropy of the Δt series. The NPT is calculated again from the modified Δt series using the technique previously described. The new NPT provides a higher value of NPT from which ILT can be computed using simple subtraction.
After ILT is identified and calculated, the ILT cause can be ascertained by analyzing the drilling parameters, such as rate of penetration (ROP), weight on bit (WOB), torque, and flow rate, using an algorithm similar to the one previously discussed.
The proposed method can be integrated with future management and well design plans to help improve drilling operation efficiency. The proposed workflow automates the entire calculation process, thereby reducing human interference and maximizing the time value of information.
Additionally, this paper proposes another simpler analysis tool that is based on pattern analysis of the final IMF obtained from the decomposition of a time series. This observation-based tool proposes that if a process is nonproductive, then the final IMF will have a downward parabolic trend. If the personnel performance is consistent, then the final IMF will have an upward parabolic trend.
This paper presents four field case studies to help prove the hypothesis of this work.
Low Salinity Water Injection: Effect of Acid and Base Functionality on Recovery Performance
Authors: Miyauchi Tomás Eduardo , Lu Yingda , Firoozabadi Abbas 
Published: October 2017

Abstract
Injection of low salinity water in some crude-rock systems may provide substantial improved oil recovery. However, the mechanisms are not fully understood. There is not much understanding of what type of crudes or what type of rocks lead to improved oil recovery from low salinity water injection. In this work, we measure acid and base functionality of the crude oil as well as brine-crude oil interface viscoelasticity and contact angles to shed light on low salinity water injection in sandstone rocks. We use three different crude oils from three different reservoirs from the Middle East. Two of the oils are heated to 55 °C to remove some of the light components to broaden the range of oil variables. We carry high salinity and low salinity water injection in Berea sandstone cores saturated with the whole crudes and the heated crudes. In some tests after high salinity water injection, we perform low salinity water injection. All rock/brine/crude systems examined show water wetting conditions. In one of the three whole crudes, we observe a significant improved recovery from 53% to 66% with low salinity water injection. In another whole crude, there is no increase in recovery with low salinity water injection. In the third whole crude, there is limited improved recovery with low salinity water injection. In the heated crude oils (with removal of light components) the recovery is improved significantly by low salinity water injection. Various measurements show that total acid number and total base number as well as the interface viscoelasticity contribute to improved oil recovery from low salinity water injection in a water-wetting state. Our data also show very little improved oil recovery when low salinity brine is injected after injection of high salinity brine. In our measurements, the pH of the produced water in the sandstone is about 10. It does not depend on the salinity of the injected brine.
Improving Chemical EOR Simulations and Reducing the Subsurface Uncertainty Using Downscaling Conditioned to Tracer Data
Authors: Torrealba Victor A. , Hoteit Hussein , Chawathe Adwait 
Published: October 2017

Abstract
Recovery mechanisms are more likely to be influenced by grid-block size and reservoir heterogeneity in Chemical EOR (CEOR) than in conventional Water Flood (WF) simulations. Grid upscaling based on single-phase flow is a common practice in WF simulation models, where simulation grids are coarsened to perform history matching and sensitivity analyses within affordable computational times. This coarse grid resolution (typically about 100 ft.) could be sufficient in WF, however, it usually fails to capture key physical mechanisms in CEOR. In addition to increased numerical dispersion in coarse models, these models tend to artificially increase the level of mixing between the fluids and may not have enough resolution to capture different length scales of geological features to which EOR processes can be highly sensitive. As a result of which, coarse models usually overestimate the sweep efficiency, and underestimate the displacement efficiency. Grid refinement (simple downscaling) can resolve artificial mixing but appropriately re-creating the fine-scale heterogeneity, without degrading the history-match conducted on the coarse-scale, remains a challenge. Because of the difference in recovery mechanisms involved in CEOR, such as miscibility and thermodynamic phase split, the impact of grid downscaling on CEOR simulations is not well understood.
In this work, we introduce a geostatistical downscaling method conditioned to tracer data to refine a coarse history-matched WF model. This downscaling process is necessary for CEOR simulations when the original (fine) earth model is not available or when major disconnects occur between the original earth model and the history-matched coarse WF model. The proposed downscaling method is a process of refining the coarse grid, and populating the relevant properties in the newly created finer grid cells. The method considers the values of rock properties in the coarse grid as hard data, and the corresponding variograms and property distributions as soft data. The method honors the fluid material balance and geological features from the coarse model. A workflow is outlined to address uncertainties in geological properties that can be reduced by integrating dynamic data such as sweep efficiency from interwell tracers. We provide several test cases and demonstrate the applicability of the proposed method to improve the history-match of a chemical EOR pilot. Further, we evaluate the fitness of different heterogeneity measures for grid-ranking of CEOR processes.
A New Approach to Determine Asphaltenes Stability
Authors: Hascakir Berna 
Published: October 2017

Abstract
Asphaltenes stability is a phase behavior phenomenon and affected mainly by the change in pressure and temperature. However, the changes in pressure and temperature lead compositional changes, hence, the dependency of asphaltenes stability on crude oil composition requires more clarity. In this study, the impact of solubility, polarity, and reservoir rock composition on asphaltenes stability for 11 different crude oil samples were investigated. All crude oil samples used in this study due to their high viscosity and low API gravity were classified as heavy oil, extra-heavy oil, and bitumen. Samples were first separated to their Saturates, Aromatics, Resins, and Asphaltenes (SARA) fractions. Based on the obtained weight percent of SARA fractions, solubility of asphaltenes in crude oil fractions was determined through Colloidal Instability Index (CII). Polarity of the crude oil samples was indirectly defined by dielectric constant measurements. Finally, the asphaltenes fractions was mixed with deionized water and then the supernatant samples were analyzed in terms of Total Dissolved Solids (TDS) and zeta potential to observe the possible interactions between reservoir rock and crude oil. Our results suggest that reservoir rock-crude oil interaction affects most the asphaltenes stability. Moreover, this interaction has positive impact on maintaining asphaltenes stability. As the asphaltenes interact more with the reservoir rock, in general, asphaltenes surfaces become negatively charged, consequently, the electrostatic repulsions created by the reservoir rock components attached to the asphaltenes surfaces keep the asphaltenes clusters apart. If the inorganic-organic interaction (reservoir rock and crude oil interaction) is insignificant, then, asphaltenes stability is determined by polarity and solubility.
Monitoring and Improvement of Waterflooding Sweep Efficiency Using Pressure Pulse Testing
Authors: Shakiba Mahmood , Hosseini Seyyed A. , Sepehrnoori Kamy 
Published: October 2017

Abstract
During waterflooding, formation heterogeneity controls water sweep efficiency. The location of water-injection wells and operational parameters should be designed based on the heterogeneity of the formation in order to maximize oil production and to avoid early water breakthrough. However, initial geologic and reservoir characterization studies may not provide an accurate view of the location of high-perm zones, channels, and fractures. In this study, we present the application of multi-well pressure pulse testing in the dynamic monitoring of waterflooding sweep efficiency and in the investigation of interwell connectivity. In a pressure pulse test, a periodic injection-rate signal comprising a series of active and shut-in cycles is superimposed on the regular schedule of a candidate injection well, and the corresponding pressure response is recorded at several surrounding wells. Because of the periodic characteristic of the pressure pulse test, pressure response at observation wells can be extracted from background reservoir pressure data; therefore, no well shut-in is required during the test. Pressure data are then transformed into the frequency domain using fast Fourier transform (FFT). Finally, using a modified analytical solution in the frequency domain, the hydraulic diffusivity coefficient is obtained. The modified analytical solution only takes pressure data at the pulsing well and the observation well; no injection-rate data is required in the analysis.
We verified the accuracy of pressure pulse testing using a waterflooding case in an inverted five-spot well pattern. The measured hydraulic diffusivity from pulse testing was in agreement with the hydraulic diffusivity coefficient calculated from formation properties. In the next step, we applied pressure pulse testing in a five-spot well pattern with a channel between one of the well pairs. Again, time-lapse analysis of the hydraulic diffusivity coefficient successfully identified the direction of the high-permeability channel, which helped prevent an early water breakthrough. In the last simulation case study, we investigated pressure pulse testing in a synthetic field-scale waterflooding project. We considered a lognormal permeability distribution to mimic formation heterogeneity. Using the information derived in this step, the zones with higher water invasion were determined, which led to modification of well operational parameters such as injection rate and bottom-hole pressures. Optimization of waterflooding design significantly improved sweep efficiency and increased the recovery factor of the process. Pressure pulse testing reasonably predicted the heterogeneity of the formation through interwell hydraulic diffusivity coefficients. Such information substantially assists in future planning and development of the formation.
Hindered Transport in Nanoporous Unconventional Reservoirs and Its Implications on IOR and Stimulation
Authors: Huseynova Jamila , Ozkan Erdal 
Published: October 2017

Abstract
This paper focuses on steric filtration of hydrocarbon mixtures in nanoporous media. Molecular filtration is described by molecular partitioning between the bulk and nanopore phases. For the hindered transport of solid particles through porous material, filtration efficiency is defined based on the ratio of the solute and pore channel dimensions. This approach is not suitable for hydrocarbon mixtures because of the dependence of molecular size and shape on thermodynamic conditions. In this work, partition coefficient is determined from equilibrium thermodynamics. Flash calculations are performed to determine the fugacity ratio and the corresponding compositions of hindered components when the unhindered hydrocarbons reach equilibrium after a change in the system pressure. The differences between the original and final pressures is the filtration pressure. Two- and three-component hydrocarbon mixtures are considered with the heaviest component being the hindered component. The effect of temperature and pressure on filtration efficiency is documented and implications on improved recovery from unconventional reservoirs are discussed. According to the results filtration efficiency decreases (more hindered components pass through the pore throat) as the filtration pressure increases and ambient temperature decreases.