bluuebunny/crossref_metadata_2025_split huggingface dataset:
Lattice Boltzmann Simulation of Phase Behavior of Hydrocarbons in Nanopores: Role of Capillary Pressure and Fluid-Solid Interaction
Authors: Huang Jingwei , Yin Xiaolong , Barrufet Maria , Killough John 
Published: October 2020

Abstract
In this work, the pseudopotential lattice Boltzmann method is employed to study the phase equilibrium in confined space. The role of capillary pressure and fluid-solid interaction are evaluated separately. In the absence of solid walls, our pore-scale simulation is consistent with the thermodynamic model coupling Peng-Robinson equation of state and capillary pressure. We prove that Young-Laplace equation and Parachor model is still valid at nanoscale. When the pore space is confined by solid walls, the heterogeneous density distributions in nanopores are discovered. The decreased critical temperature and increased critical density are observed under confinement.
In addition, the effect of fluid-solid interaction strength on phase behavior is studied. It is found that a larger fluid-solid force leads to a more heterogenous density distribution in nanopores. However, the average liquid/vapor density and critical temperature are not significantly affected by the strength of fluid-solid interaction. The critical pressure, on the other hand, is lower when the fluid-solid interaction is stronger. The coexistence curves and saturation pressures in nanopores with different fluid-solid force are presented which can be characterized by using contact angle. Finally, the phase behavior in a complex pore structure is calculated. This work illustrates that implementing capillary pressure or critical shift alone cannot fully describe the confined phase behavior.
Digital Slickline: Case Studies Using an Electro-Mechanical Setting Tool and Downhole Anchor Tool
Authors: Heaney Frank , Mlcak Matthew 
Published: October 2020

Abstract
Digital slickline (DSL) using radio frequency (RF) communications for on-command surface controlled explosive trigger tools has been available for years (Heaney et al. 2018). Unfortunately, the non-explosive electro-mechanical downhole power unit (DPU) setting tool could only run in timer mode, and all key performance indicators (KPI), including motor current & voltage, force and rod position were only available in the tool’s memory. The expansion of DSL services led to the development of a powered mechanical platform, and the primary tool upgraded was the DPU to an elite downhole power unit (EDPU). This enhancement allows for on-command surface control and real-time KPI sensor data that was formerly only in the tools memory. Also available are the real-time DSL data, including; casing collar locator (CCL), pressure, temperature, inclination, relative bearing, axial & radial vibration, and battery voltage & current that helps corroborate a successful plug set. Case histories presented will show how all the surface readout (SRO) data provide conclusive confirmation in-situ that the barriers set as planned, and provide a repeatable signature of a mechanical plug set. We will also show examples of plugs that exhibit the expected digital signature but did not pass a mechanical integrity test to confirm adequate isolation. Additional tools in the powered mechanical toolbox include an on-command release tool (ESRT) and a downhole anchor tool (EDAT). All devices can be run in combination if required, and each apparatus has a unique address with individual surface commands. The EDAT & EDPU combination expand intervention services with an extremely high push & pull force, which allows for pulling of subsea crown plugs, heavy-duty fishing, pulling retrievable plugs and many other applications. The EDAT can be set up to run in industry-standard 3 ½, 4 ½, 5 ½, and 7inch pipe sizes and can be modified to allow pulling of oversized crown plugs those outside diameters (OD) are more significant than the dimensions of 7inch pipe.
Understanding Real-Time Job Signatures on Deepwater Cementing Jobs with Dynamic Losses
Authors: Dooply Mohammed , Schupbach Michael , Hampshire Kenneth , Contreras Jose , Flamant Nicolas 
Published: October 2020

Abstract
Two of the most important parameters to monitor during a primary cementing job are the flow rate in and return flow rate measurements. To achieve optimum quality control of a primary cementing job, measuring annular return rates and comparing them with simulated data in real-time will provide better understanding of job signatures and result in the best possible top-of-cement estimation prior to running any cement evaluation log or taking decision to continue drilling the next section of the well.
The return rate job signature along with the wellhead pressure is essential to understand the behavior and discrepancies between simulated and acquired surface data. Therefore, to assess the risk of job issues, such as unsuspected washout and lost circulation among others, accurate measurements of the return rate are critical.
Historically, cement job evaluation has been limited by the fact that most drilling rigs do not have an accurate flow meter installed on the annulus return line, and a simple verification of mud tanks volumes versus pumped volume, as reported by drillers or mud loggers, more than often results in an unreliable assessment of the volume lost downhole, due to the unfamiliarity with the U-tubing effect and lack of data consolidation from the cement unit (flow rate in) and the rig (flow rate in & flow rate out).
This paper will review a solution developed to mitigate the lack of a direct flow rate measurement by computing and displaying the return rate using either a paddle meter measurement or the derivative over time of the volume observed in the rig tanks.
A Step Change in Cementing Mitigating Sustained Casing Pressure
Authors: Heinold Thomas , Porter D. Steve , Qasmi Urooj , Taoutaou Salim 
Published: October 2020

Abstract
Wellbore construction practices are complex. Achieving dependable zonal isolation is a critical and challenging process to optimizing asset life and minimizing future well intervention. Sustained casing pressure challenges related to poor zonal isolation are well documented and can impact production that may require significant remedial well intervention. The need to address these challenges called for revisiting cementing operational practices and lead to the development of a Basis of Design (BoD) document as a tool to help manage well design practices and standards.
As common industry practice to prevent fluid migration, slurry designs should be gas tight. To avoid unwanted wellbore fluids to migrate to surface, two things are required: less time to initiate migration and the lack of a flow path. With analysis of the current cement slurries, designs were unable to perform successfully on inflow tests due to low temperature of the zones to be cemented, increasing the transition time for a slurry to move from liquid state to solid phase. With extensive laboratory testing it was concluded that current designs were not addressing the bulk shrinkage phenomenon of cement, which could lead to the creation of micro annulus creating conduits for fluid migration. This paper will discuss the detailed analysis and testing of the current and new designs and techniques validated by laboratory tests and field executions (Cement Bond Logs) to prevent fluid migration and ensure that dependable long-term zonal isolation was delivered. Mud displacement mechanics needed to be optimized to reduce the risk of mud on the wall phenomenon. This included the design of spacers that increased the annulus mud displacement efficiency, improved standoff and finally optimum displacement rates to create sufficient annular velocity.
A comprehensive look at all the pertinent steps in the construction of the well starting from the drilling phase, through cement job design, preparation and execution was required to ensure that the best practices are adopted to achieve the best results. Slurry selection, spacer formulation, centralization, hole cleaning and excess volumes were all at the center of the improvements that were necessary to achieve optimum results. A BoD document was developed as a roadmap for cementing to further enhance wellbore integrity. It formalized the planning, design and job execution practices and specified the slurry design, placement, and verification criteria for each casing section.
Several cement jobs have been executed using the newly implemented practices that resulted in excellent zonal isolation results, which were verified through cement integrity logs. Since the implementation in all subsequent wells, no casing-casing annulus pressure issues have been reported.
Novel Approach to Extend Electrical Submersible Pump Run Times In the Williston Basin
Authors: Bestgen Daniel , George Jacob , Mullins Karen , Beans Gina , Penkala Joseph 
Published: October 2020

Abstract
Williston Basin oil-producing wells utilizing Electrical Submersible Pump (ESP) lift undergo severe challenges with respect to scale and corrosion due to high TDS brines (250,000 – 320,000 mg/L) and high shear and high temperature operating conditions (275ºF-325ºF at the ESP). Corrosion most commonly attacks the ESP, lower tubing, andannular space locations where the cable armor contacts the metal. Scale is primarily calcium carbonate due to ~20,000 mg/L of calcium in the brine and is commonly seen around the ESP where temperatures are highest. The severity of these conditions canlimit ESP run times to 3-4 months until failure.
Challenges for suitable protection from scale and corrosion include using specialty chemicals that provide temperature stability (325°F for the ESP environment and -40°F for winter temperatures at the surface), capillary qualification (the preferred delivery method), high TDS brine compatibility, and custom performance needs to address the various corrosion mechanisms. To this end, two strategies were developed combining uniquely qualified chemistries with specialized application. A new high temperature/high TDS scale/corrosion inhibitor was developed for delivery down the capillary (Menendez et al. 2019). A corrosion inhibitor was then identified formitigating cable armor-tubing corrosion suitable for application as a pre-conditioning batch treatment during ESP installation.
Using ESP run time as a metric and comparing treatments with a conventional scale/corrosion inhibitor combination, it was found that the new combination product provided a 73% increase in run time (230 v. 132 days). When the pre-conditioning corrosion inhibitor treatment was done in conjunction with the new combination product, the run time showed a 100% increase (264 v. 132 days). These findings are discussed in conjunction with improved practices for ESP management under severe corrosion and scale challenges. It is important to consider that any extension in ESP run time gained through mechanical or chemical means offers improved well production, lower operating expense, and improved profitability to the producer.
Free Gas and ESP; Case Studies Illustrating the Difference Between Flowrate Oscillations, Gas Locking and Instability
Authors: CAMILLERI Lawrence 
Published: October 2020

Abstract
Electrical submersible pumps (ESP) oil well production often requires handling large amounts of free gas, leading to numerous ESP trips, which limits drawdown. To maximize production and eliminate downtime, a technique was developed to distinguish between three possible different causes i.e. gas locking, ESP flowrate oscillations, and dynamic instability and thereby improve design and operating procedures. The theory is illustrated with case studies and real time data. The main objective was to determine the cause of observed well instability and understand the interaction between the pump and the remainder of the wellbore. In addition to using classical steady-state nodal analysis, the analysis used downhole flowrate simulations to capture ESP transient oscillations. Furthermore, system dynamic stability analysis identified when and why the interaction between the pump and the wellbore results in flowrate and pressure instabilities, which can lead to pump mechanical failure. Combining holistic well analysis with a review of case studies led to identifying several types of gas-induced problems, root causes, and solutions. For each type, diagnostic techniques were developed in addition to design and operational recommendations. Interestingly, in some cases, where traditional diagnostics would have pointed to gas locking in the pump as a root cause, the new analysis demonstrated that well slug flow regime dominated the well and ESP behaviour. A key conclusion from the analysis was that real-time measurement of intake, discharge, and wellhead pressures is necessary to correctly distinguish between pump gas lock, well flow regime issues (e.g. slugging) and system instability. Furthermore, real-time downhole measurement of transient flow rate through the pump is indispensable feedback to operators for managing wellhead pressure and pump frequency with the aim of maximizing drawdown, stabilizing the well, and extending the ESP run life. A key finding is that irrespective of the cause, it is always best to operate the ESP at rates greater that the best efficiency point, which usually requires over staging the design. Finally, the case studies presented in this paper illustrate the importance of capturing the relative slopes of the pump and well system curves as well as how they change with time. Combining new models with real-time data improves the accuracy of diagnostics and therefore enables increasing the GVF that ESP wells can handle and thereby maximizing production by either eliminating trips and/or maximizing drawdown.
High Resolution Reservoir Characterization While Drilling: First Case Study from the Middle East Carbonates with Innovative Multi-Measurement Borehole Imager for Non-Conductive Mud
Authors: Maalouf Janine , Lyonga Sammy Molua , Shasmal Sudipan , Ali Humair , Shrivastava Chandramani , Goraya Yassar , Ashraf Muhammad , Khemissa Hocine , Al Dhafari Bader Mohamed , Al-mutwali Omar , Alfelasi Ali Saeed 
Published: October 2020

Abstract
The Middle East Carbonates have been prolific hydrocarbon reservoir, producing through different units of Cretaceous, Jurassic and Permian over decades. However; inherent heterogeneity, karstification and fracturation in various facies often spring surprises in development wells; and many wells drilled with Oil-base mud (OBM) could not image these features with logging while drilling (LWD) technology for characterization and model updating since e-line logging is usually discouraged in such wells. This work presents the first ever case study from the Middle East Carbonates where an innovative new technology LWD borehole imager for OBM was deployed to understand the subtle geological variations that control the fluid flow.
The multi-measurement borehole imaging technology was deployed while drilling with OBM to acquire apparent resistivity and ultrasonic images simultaneously to image the subtle geological features that often control the reservoir properties but didn’t get characterized earlier due to technology limitations. Around 13,000ft of lateral was logged while drilling through Cretaceous carbonates, traversing through different layers going up and down in stratigraphy; showcasing subtle variations with complementing images that helped understand the vug distribution, bioturbation, faults and dissolution seams in addition to the bedding boundaries.Vugs tend to control the fluid flow rates in many facies, and vug density curves derived from the images helped in characterizing the key-intervals. Qualitative trends are validated with mobility estimated from independent LWD measurement, providing much-needed confidence in the new technology imaging. Also, the correspondence of image facies to the fluid facies derived with surface logging while drilling confirmed the subtlety observed in the geological variations through the lateral.
This first-ever case study provides plethora of new information for model updating that was hitherto unavailable for some reservoirs where development wells were drilled with OBM, and existing imaging technology of gamma ray, photoelectric factor and density were not able to decipher any of such features that are imaged now while drilling with multi-measurement technology.
An Electro-Kinetic Study of Amino Acid and Potential Determining Ions for Enhanced Waterflooding in Carbonate Reservoirs
Authors: Lara Orozco Ricardo A. , Abeykoon Gayan Aruna , Okuno Ryosuke , Lake Larry W. 
Published: October 2020

Abstract
Reservoir rock wettability plays an important role in waterflooding especially in fractured carbonate reservoirs because oil recovery tends to be inefficient from the mixed-wet or oil-wet rock matrix. Improved oil recovery has been observed by adjusting the concentrations of potential-determining ions (PDIs) to alter the wettability of carbonate rocks.
Our previous study showed that the oil recovery from carbonate reservoirs by waterflooding can be enhanced by the addition of glycine, the simplest amino acid. The interaction of glycine anion and oil-wet carbonate surfaces was confirmed in contact-angle measurements, and yielded the incremental oil recovery in imbibition experiments. This paper presents a surface complexation model (SCM) for the interaction between glycine and oil-wet carbonate surfaces that considers the impact of temperature, pH, salinity, and the concentration of PDIs.
The calculation results showed that the SCM qualitatively predicts the strong affinity of glycine for the oil-wet carbonate surface to desorb the carboxylic acids from the surface. However, the SCM needs to be calibrated with experimental data for quantitative accuracy with/without glycine. A lower isoelectric point (pI) of glycine tended to result from lower salinity brine that had a higher equilibrium pH. The temperature was found to significantly affect glycine's affinity for the surface. The calculated amount of carboxylic acid adsorbed on the surface significantly decreased with increasing glycine concentration at 95°C. The SCM suggested glycine's potential to change the wettability of oil-wet carbonates at high salinity, high hardness, and high temperature.
Effect of Choke Management in Optimizing Shale-Oil Production with Models of Different Recovery Driving Mechanisms
Authors: Wijaya Nur , Sheng James J. 
Published: October 2020

Summary
Economic production from shale oil reservoirs relies on the longevity of conductive fractures. Choke or drawdown management is believed to better preserve the fracture conductivity during the early life of the wells, which thus potentially leads to a higher ultimate oil recovery. However, there is no strong consensus among the previous literature as to whether choke management can offer the incremental oil recovery in the long-term. Even if it can, the mechanism is not well understood, and the economic benefit can be challenged, because the choke management slows down the early oil production, which is worth the most in terms of Net Present Value (NPV).
In this study, a series of coupled flow-geomechanical numerical simulations is performed to examine the effect of choke management on the ultimate oil recovery and NPV. We built multiple reservoir realization models, each of which is validated based on the same field production data from Middle Bakken shale-oil reservoirs to perform probabilistic production forecasts. The different reservoir realization models are built to assess the uncertainty in the Stimulated Reservoir Volume parameters, including natural fracture spacing, water saturation in the matrix and fracture, and formation compressibility. The different reservoir parameters lead to each model having different primary recovery driving mechanisms of oil recovery, including imbibition and compaction drive. In each simulation run, stress-dependent permeability phenomena during fracturing and flowback are modeled to more closely simulate proppant crushing and embedment. Our model carefully simulates the matrix, natural, and hydraulic fractures separately, because each of these media demonstrates different stress sensitiveness.
This study quantitatively demonstrates that the choke management seems to increase both the ultimate oil recovery and NPV if the oil recovery is strongly driven by imbibition. A mechanistic discussion for this claim is presented. We have also shown that this claim can straighten out the mixed conclusions among some previous papers. As a result, this study proposes the evaluation of the dominant driving mechanism of shale-oil recovery for the optimum design of the choke management. Moreover, this study also attempts to propose the optimum ramping-down rate of the choke. For example, if the reservoir demonstrates a strong imbibition, the optimum choking rate is between 500 and 100 psi/day. Meanwhile, if the reservoir demonstrates a weaker imbibition, the optimum choking rate is between 50 and 10 psi/day. These optimum range is shown to be consistent, regardless of the objectives, whether to optimize the ultimate oil recovery or NPV.
Geomapping an Oil/Water Contact in a 45-Degree Inclination Well Unleashes Ultra-Deep Resistivity Potential, a Case Study from Kuwait
Authors: Al Khalifa Nasser , Hassan Mohammed , Joshi Deepak , Tiwary Asheshwar , Al Shammari Yousef Suhail , Clegg Nigel , Clarion Benjamin , Kharitonov Alexander , Pan Li 
Published: October 2020

Abstract
Through decades of production and water injection, Umm Gudair reservoir fluid distribution have changed significantly, resulting in an increase of uncertainties on fluid levels and subsequent water cuts in production. Different well architectures have been implemented pilot holes, deviated wells or horizontals, but the development of such mature fields comes with inherent difficulties, as offset data does not necessarily reveal the current reservoir properties and fluid contact position. Frequently, costly and time-consuming additional operations such as cement plugs or sidetracks are required to resolve an unforeseen water saturation of the reservoir. However, these methods have a limited efficiency in reducing the water percentage over the time of well production.
In this challenging environment, the Umm Gudair asset has implemented a different approach to well construction built upon the combination of an ultra deep resistivity tool with a previously unattempted benchmarking scenario for a look around inversion. Drilling a trajectory of 45° inclination in order to proactively identify the oil water contact (OWC) in the far field below, and confirm this forecast with an actual resistivity measurement during its penetration. This unprecedented process shows great opportunities in optimizing future well placement and production performances. The main inputs in this success come directly from the capability of the inversion of the electromagnetic measurements in various drilling conditions, as well as a thorough preparation and collaboration between the operator and the service company.
Before implementing this technology, it is critical to assess the expected performance by understanding the different parameters which affect the performance of the tool. The study of the different offsets gave an overview of potential resistivity contrast between fluids and their contact positions. The pre-well study is therefore essential to optimize depth of detection (DOD) versus sensitivity through forward modeling of various frequencies and spacing selections. This phase is also necessary for the team to understand what can be expected from the service with the elaboration of different scenarios based on theoretical tool responses and communication protocol.
This case study shows how an innovative scenario and collaboration between operator and service company reveals a new capability to place a well drilled at mid-angle in the lowest water saturated part of the reservoir using inverted resistivity measurements. The economic benefit and post job analysis conducted post well confirm the promising outlooks of utilizing an ultra-deep resistivity service in a mature field environment.