bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Process for Improved Oil Recovery from Water Injection by a Functional Molecule at 100 ppm Concentration
Authors: Kar Taniya , Chávez-Miyauchi Tomás-Eduardo , Firoozabadi Abbas , Pal Mayur 
Published: September 2019

Abstract
Low salinity water injection when effective in increasing oil recovery is often thought to be through increase in water wetting. Recently, oil-water interfacial rheology has been suggested to be related to oil recovery from low salinity water flooding. We have also discovered that addition of a very small amount of a functional molecule in the injection brine increases oil recovery significantly. Quantitative effect of interfacial elasticity and the effect of rock on oil recovery is investigated at 100 ppm concentration in this work for the first time. A light crude oil is used in four sets of waterflooding experiments in a carbonate rock. The injection brine is modified by adding 100 ppm of a non-ionic surfactant. To understand the recovery performances, interfacial viscoelasticity, interfacial tension and contact angle measurements are performed using brines of varying salinities. In interfacial rheology the effect of equilibration of the aqueous phase with the rock is also investigated. Additionally, adsorption of the surfactant in the carbonate rock is investigated for various aqueous phases via UVvis spectrometry. Crude oil, calcite and reservoir brine show moderate oil-wetting behavior. Addition of surfactant molecules makes the system more water-wet, however, the change is not pronounced. From coreflooding experiments, addition of surfactant in high salinity brine increases recovery by over 20% which we interpret to be due increase in interface elasticity. The phase angle which is a direct measure of interface elasticity decreases by 70% in an aqueous phase at about 4 wt% salt due to the surfactant. High interface elasticity reduces oil snap off and increases oil recovery. An effective molecule dissolved in water can increase the interface elasticity significantly. In relation to low salinity water injection we have established that there is an optimum salt concentration for high oil recovery. The injection of an aqueous phase without salt gives a lower recovery than injection of say 0.1 wt% salt in the injected water.
We have introduced a new IOR process based on interface elasticity which requires a very low concentration of a non-ionic surfactant. The process is neither through wettability alteration nor through significant change in IFT. The chemical we have used is environmentally friendly and of low cost. It has very low adsorption onto the rock surface.
Estimating Fracture Network Area and SRV Permeability by Analyzing Offset Well Pressure Measurements during Fracturing
Authors: Seth Puneet , Manchanda Ripudaman , Elliott Brendan , Zheng Shuang , Sharma Mukul , Hwang Jongsoo 
Published: September 2019

Abstract
During stimulation of unconventional reservoirs, offset well pressure measurements are often used to estimate hydraulic fracture geometry. These measurements can also be used to make a quantitative estimate of the created fracture network area and the permeability of the stimulated rock volume (SRV) around the hydraulic fractures. Offset well pressure measurements recorded in the field clearly show a change in the pressure response of the monitor well when the injection rate in a nearby fracture treated well is changed. The shut-in period between two frac stages in the treatment well corresponds to a distinct pressure fall-off in the monitor well. We present a workflow where we analyze and match this pressure fall-off in an offset monitor well in response to fluid leak-off from a hydraulic fracture in the treatment well to estimate SRV permeability and the created fracture network area. The workflow and model are applied to field data from the Permian Basin.
A fully-coupled, 3-D, poroelastic reservoir-fracture simulator has been used to simulate pressure fall-off in the offset monitor well. Field data and simulation results are presented to show that during shut-in between two frac stages in the treatment well, a decrease in the injection rate causes the monitored offset well pressure to fall-off. We find that this fall-off in pressure is influenced by leak-off from the treatment well fracture. During the shut-in period, fluid leak-off from the treatment well fracture into the SRV region decreases the width of the fracture which consequently affects the stress-shadow and the poroelastic pressure fall-off in the offset monitor well. The pressure fall-off in the monitor well is, therefore, shown to be caused by 1) the fluid leak-off from the monitor well fracture and 2) stress-shadow relaxation around the monitor well fracture as fluid leaks-off from the nearby treatment well fracture into the formation.
We present a new method to estimate the permeability of the stimulated region around the created fractures. We show that, along with the permeability of the SRV region, the stress-shadow of the treatment well fracture on the monitor well fracture also has a significant impact on the pressure fall-off in the monitor well. We use a conceptual model to estimate the created fracture network area which can be used as a metric to identify the effectiveness of a frac job and provide insights into the generated fracture complexity during the frac job. In addition, the estimated SRV permeability and fracture network area are critical inputs in production forecast simulations that can guide an operator to make better economic decisions in a relatively inexpensive manner.
Improved Communication and Autonomy with Downhole Memory Logging Tools
Authors: Kupchenko Shawn , Gilhooley Neill , Ash Sam , Carrahar Alyn 
Published: September 2019

Abstract
Openhole logging tools have been used without wireline in memory logging for 20 years, in an important and growing market. A new system in field trials in Canada and Russia in 2019 further expands the operating envelope overlap between wireline and logging-while-drilling by making step changes in communications, autonomy, performance, and reliability. The new approach advances the logging of horizontal and challenging wells, and permits operations in managed pressure drilling and foam drilled wells.
The vast majority of openhole memory work is achieved with a hydro-mechanical system that indicates successful deployment but lacks two-way communication between the engineer at surface and the tools downhole. Pressure-pulse communications have been used for 10 years with a wide range of measurements including memory logging with wireline formation testers. The experience gained from operating these systems informed the development of a new system that uses drillpipe rotation to communicate to the tools, pressure pulses to reply for the uplink, and a more powerful downhole processor. These enhancements in autonomy and communication improve the outcome of logging jobs.
The system incorporates a new rotation downlink method which employs data from an angular rate sensor to identify a series of commands sent by rotating the drillstring. Control software in the downhole tools executes the commands, and replies are transmitted uphole by pressure pulses. The toolstring is released from a safe ‘garage’ position inside the drillpipe and deployed into openhole, with the top of the toolstring retained by a no-go. The engineer is supplied with far more diagnostic information than previously, including the axial position of the tools, with context sensitive encoding to provide maximum troubleshooting information to the surface over a limited bandwidth channel. The pressure-pulse downlink remains in place as a secondary method. Other material improvements include high data sampling rate, debris tolerance and downhole recovery strategies. All of these advances improve the autonomy of the downhole memory equipment as well as the real-time communication and control from the surface.
Autonomous memory logging toolstrings, with powerful downhole software and rotation downlink communications, are important components in improving the performance and reliability of these successful and innovative formation evaluation systems.
An Early Production Comparison of Northern White Sand and Regional Sand in the Permian Basin
Authors: Williams Ryan , Artola Pedro , Salinas Javier , Mirakyan Andrey , MacKay Bruce , Hoefer Ann , Kraemer Chad , Reese Harrison , Roybal Zack , Williamson Brant 
Published: September 2019

Abstract
Use of regional sand in the Permian Basin dramatically increased in 2018. Regional or in-basin sand is often perceived as lower quality compared to northern white sand (NWS); however, its use is fairly new, and production data has not been available to determine if, or in what cases, higher quality matters. This paper presents the results from a production comparison of Permian Basin wells that were hydraulically fractured with NWS and regional sand or both.
A dataset consisting of approximately 450 wells completed with NWS or regional sand or both within the Delaware and Midland Basins was studied to determine the relationship between production performance and sand type (or quality). To evaluate the effect of sand quality in well production, the dataset was divided in smaller groups of wells with similar reservoir characteristics and completion practices. The initial phase of the study was completed using public domain production data, while the second phase focused on the development of regional reservoir models to forecast production of wells using NWS or regional sand or both.
When analyzing an area containing sufficient wells for a reliable comparison, the survey revealed no statistically significant difference in production for wells that used NWS versus regionally sourced sand. Models were built to predict differences in the production performance of each sand type. These models take into account and demonstrate the effects of differences in sand properties, as well as the impact of the favorable economics associated with regional sands. It was confirmed with the study that the sand type is not a critical factor in regards to production performance when completing wells that are hydraulically fractured in ultralow-permeability nonconductivity-limited reservoirs.
This paper presents an early look at the production numbers of West Texas wells completed with regionally sourced sand in the Permian Basin. The results of the study will encourage operators to further contemplate the use of regional sand when completing wells in ultralow-permeability shale reservoirs. This dataset will continue to evolve and reveal the effects of regional sand over the life of the well; this will be presented in a future paper.
A Risk-Based Approach to Evaluating, and Rationalizing, the Portfolio of Company HSE Programs
Authors: Cunningham Andrew , Wentzel Nada , Knode Tom , Pooley Tony 
Published: September 2019

Abstract
In order to improve HSE performance many companies have implemented voluntary (i.e. non-regulation driven) programs designed to engage supervisors and employees and reduce injuries and incidents. Over the years these programs have had significant effect in improving performance and making the workplace safer. While done with the best intentions, most programs introduce an element of administrative burden on the organization and sites. The cumulative impact on a supervisor's daily activities can be substantial and result in excessive time spent in front of a computer, rather than with their teams. This means less opportunity to provide leadership on safety and consequently, undermine efforts to improve.
In 2017, based on a combination of employee surveys and safety stand downs Dyno Nobel North America (‘DNA’ or the company), a global explosives manufacturer and service provider, identified the need to evaluate the burden on the organization of safety programs to rationalize and improve them as appropriate. One of the main concerns of this effort was how to remove or modify these programs to be less of a burden, yet not increase the risk. It can be related to the game Jenga®, where players remove blocks from a stack without destabilizing the structure.
DNA engaged a consultant, The Jonah Group, to build a risk model based on the principles of process safety management interwoven with the understanding of human factors and performance. Once the model was built, it was piloted at three of the company's field sites to ensure efficacy and adjust as necessary. Afterwards, the model was used at nine field locations. The evaluation included a review of equipment, process and procedure, and centered around interviews with supervisors and front-line employees. Surveys were conducted with supervisors to complete the view of where they spend their time.
Results and recommendations were summarized in a report. One of the key findings was that while there were opportunities to improve certain elements of the voluntary safety programs, there were more significant opportunities with regards to management of change, process safety and risk awareness, site safety leadership, communication, and process efficiency. The recommendations will help the company improve organizational effectiveness and free up supervisors to better oversee, and lead, site safety.
Numerical Investigation of EOR Applications in Unconventional Liquid Reservoirs through Surfactant-Assisted Spontaneous Imbibition SASI and Gas Injection Following Primary Depletion
Authors: Zhang Fan , Saputra I. W. , Adel Imad A. , Schechter David S. 
Published: September 2019

Abstract
Surfactant-Assisted Spontaneous Imbibition (SASI) and gas injection have been proven to improve production from Unconventional Liquid Reservoirs (ULR). However, the novelty of the method has resulted in a few publications to date. This study utilizes numerical modeling to upscale laboratory data of SASI for completion purposes and gas injection plus SASI for EOR. Novel gas and aqueous-phase injection strategies following primary depletion are designed based on actual completion and production data. Multiple sequencing configurations for both surfactant and gas injection are tested to propose the best combined-EOR scheme for ULR.
Parameters related to the mechanism of SASI and gas injection are retrieved from CT-generated core-scale model of laboratory experiments. SASI and gas injection experimental results were upscaled to model production response of a hydraulically fractured well with realistic fracture geometry and conductivity. The core-scale model was created to determine the diffusion coefficient, relative permeability, and capillary pressure curves by history-matching the laboratory data. The field-scale model was developed with a dual-porosity compositional model to predict production enhancement for various combined-EOR schemes in ULR.
Wettability and IFT alteration are the two primary mechanisms for SASI in enhancing production. Experimental studies revealed that surfactant solution recovered up to 30% OOIP, whereas water alone only recovered approximately 10% OOIP. Capillary pressure and relative permeability constructed from scaling group analysis and core-scale numerical models showed that surfactant addition enhances the two curves. On the other hand, gas injection EOR was found to be driven by multi-contact miscibility and diffusion. Parameters related to both methods were applied to the field-scale model for multiple completion and EOR schemes. Results demonstrate that the combination of SASI and gas injection possesses significant potential in improving production rates and estimated ultimate recoveries (EUR) in ULR. Soak times, surfactant concentration, injection pressure, duration of the cycle, and cumulative gas injection control the level of enhancement. With a large number of control variables, specific customizations can be optimized to suit criteria of different field applications.
Overcoming Geological and Geomechanical Challenges for Drilling High Angle Well in Deep Offshore Gulf of Mexico: Example from Buckskin
Authors: Ait-Ettajer Taoufik , Giannangeli Federico , Wood Jonathan , Mookanahallipatna Lakshmikantha 
Published: September 2019

Abstract
The Gulf of Mexico, and more precisely the Wilcox trend, has long been considered as challenging area for developing profitable hydrocarbon fields. In fact, the safe drilling of deep offshore wells needs to take into account the geological and geomechanical complexities, generated by the different sedimentological and tectonic events that accompanied the development of the Wilcox trend.
In the case of Buckskin field, located in Keathley Canyon protraction (Figure 1), and in order to overcome those challenges, we developed a workflow that ranks all the parameters related to the geometry, the geology, the rock quality and the geomechanics characteristics of the reservoir. The core of the workflow is articulated around a probabilistic method that will assess the uncertainty of the productivity index, based on experimental design and Monte Carlo simulation. The proposed workflow allowed the optimization of the PI of the well thanks to a highly deviated reservoir section at a depth below 24,000’, combined with an optimal fracking job.Figure 1Location of Buckskin field
After a brief introduction of the general context of the Buckskin field, we will review the notion of the PI, then we will review the adopted process prior to the geological and geomechanical processes for modeling the rock properties and stresses and their corresponding uncertainties. The selected design of experiment approach will then be described then we will discuss the outcome.
Educating Future Drilling Engineers for the Digital Era
Authors: Eustes III Alfred W. , McKenna Kirtland I. , Zody Zach J. , Healy Carl , Lang Camden , Joshi Deep , Yow Stephen , McGowen Kyle 
Published: September 2019

Abstract
Drilling education must evolve continuously to keep up with the changes in the drilling industry. Part of that evolution includes the addition of data analytics in drilling operations. In addition, having a "hands on" experience of actual drilling operations is an important part of the drilling engineering educational process. At the Colorado School of Mines, both goals are achieved using a new coring rig equipped with a high-frequency data acquisition system.
A Sandvik DE 130 Diamond Coring Rig was acquired by the school through a grant from Apache Corporation that has proven to be an excellent analog to full-scale petroleum rigs. It has all drilling subsystems such as rotary, hoisting, power, and circulation. A data acquisition system has been added that tracks accelerations as well as various drilling operational parameters. During experiments, each student has an opportunity to operate the driller's controls and experience the complexities associated with drilling operations including the occasional error. The retrieved core helps the student correlate the formation with drilling data.
The inclusion of the drilling experience in the curriculum has benefited the students in several aspects. This experience has helped students visualize drilling operations and understand complexities and challenges associated with drilling. During the drilling operations, if any problems arise, the students have a chance to troubleshoot those problems in real-time and apply their theoretical knowledge. Operational safety and stop work authority are also a focus and demonstrated by students. This is likely to be the first experience most students have with high-frequency drilling data analysis. Monitoring, collecting, and handling real high-volume data gives a first glimpse into the complexities of data analytics. Noisy realtime data and errors are real and observed by the students. They also learn to handle and analyze high- frequency drilling data identifying normal trends and abnormalities. This coring rig has enhanced the drilling engineering education and data analysis skills of our students.
This work outlines a novel teaching methodology that combines the practical understanding of drilling and the application of data analytics. Getting out to the field and actually drilling rock has enhanced our drilling curriculum to align it with the latest industry practice and to educate future drilling engineers.
iSCAL for Complete Rock Characterization: Using Pore-Scale Imaging to Determine Relative Permeability and Capillary Pressure
Authors: Lin Qingyang , Alhammadi Amer M. , Gao Ying , Bijeljic Branko , Blunt Martin J. 
Published: September 2019

Abstract
We combine steady-state measurements of relative permeability with pore-scale imaging to estimate local capillary pressure. High-resolution three-dimensional X-ray tomography enables the pore structure and fluid distribution to be quantified at reservoir temperatures and pressures with a resolution of a few microns. Two phases are injected through small cylindrical samples at a series of fractional flows until the pressure differential across the core is constant. Then high-quality images are acquired from which saturation is calculated, using differential imaging to quantify the phase distributions in micro-porosity which cannot be explicitly resolved. The relative permeability is obtained from the pressure drop and fractional flow, as in conventional measurements. The curvature of the fluid/fluid interfaces in the larger pore spaces is found, then from the Young-Laplace equation, the capillary pressure is calculated. In addition, the sequence of images of fluid distribution captures the displacement process. Observed gradients in capillary pressure – the capillary end effect – can be accounted for analytically in the calculation of relative permeability.
We illustrate our approach with three examples of increasing complexity. First, we compare the measured relative permeability and capillary pressure for Bentheimer sandstone, both for a clean sample and a mixed-wet core that had been aged in reservoir crude oil after centrifugation. We characterize the distribution of contact angles to demonstrate that the mixed-wet sample has a wide range of angle centred, approximately, on 90°. We then study a water-wet micro-porous carbonate to illustrate the impact of sub-resolution porosity on the flow behaviour: here oil, as the non-wetting phase, is present in both the macro-pores and micro-porosity. Finally, we present results for a mixed-wet reservoir carbonate. We show that the oil/water interfaces in the mixed-wet samples are saddle-shaped with two opposite, but almost equal, curvatures in orthogonal directions. The mean curvature, which determines the capillary pressure, is low, but the shape of the interfaces ensures, topologically, well-connected phases, which helps to explain the favourable oil recovery obtained in these cases.
We suggest that the combination of imaging and flow experiments – which we call iSCAL – represents a compelling development in special core analysis. This methodology provides the data traditionally acquired in SCAL studies, but with insight into displacement processes, rigorous quality control, and flexibility over sample selection, while generating detailed datasets for the calibration and validation of numerical pore-scale flow models.
Maximizing Organizational Effectiveness by Creating a Culture of Alignment
Authors: Lau Hon Chung , Pang Michael 
Published: September 2019

Abstract
Oftentimes an organizational transformation fails not because of external reasons but internal resistance. A step often neglected by senior management in organization transformation is aligning the transformation process with the corporate culture. When a transformation works against established corporate culture, it will be rejected by the organization and will eventually fail despite the best efforts by senior management. However, if an organization transformation is closely aligned with the corporate culture, its chance of success is greatly enhanced. In this paper, we propose a step-by-step procedure to align an organization transformation process with the four layers of corporate culture. This can be pictorially illustrated by the Corporate Cultural Onion Model and the Simple Lever Model of Organizational Alignment.