bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Surveillance with 4DVSP - A Case Study in a Kuwait EOR Steam Flood Project
Authors: Al-Mutairi Amal , Al-Haqqan Hamad , Ren Zu Biao , Tinnin John , Randazzo Santi , Pare Antoine 
Published: October 2017

Abstract
Kuwait Oil Company conducted a 4DVSP steam flood monitoring program in a heavy oil field to help optimize development options. The baseline survey for this 4DVSP was acquired in January 2016 and the monitor survey was acquired in January 2017. The key objectives for this reservoir surveillance project include acquiring a repeatable baseline survey; image two vertically stacked thin reservoir units, perform characterization to understand reservoir complexity and lateral barriers, and estimate the steam chest size (sometimes referred to as a steam chamber) after 30 days of steam injection.
The 3DVSP survey took less than a week with rigless acquisition only during daylight hours. The survey area was fairly congested with infrastructure making it difficult to manoeuvre between source positions easily. To tackle this, two groups of vibrators were used with a source driven acquisition technique. This meant much of the acquisition process was automated providing better efficiency and reducing human error.
The resulting data was processed and imaged with proprietary 3DVSP Kirchhoff depth migration algorithms. Due to an innovative acquisition design, output frequencies were 30% higher than achieved in previous VSPs or seismic data in the area. Velocity models were derived using the zero offset VSP data and a geomodel was derived from well data. The migration was sampled at dX/dY/dZ values of one meter each to help create a high resolution image. Synthetic seismograms from well logs and corridor stacks from the zero offset VSP were used to accurately tie the well data to the 3DVSP volume. This data volume was mapped using seismic workstations and amplitude anomalies were obvious around the steam injected well making possible the mapping of the steam chest. Deterministic inversions from this data help identify facies changes and channels explaining the direction and pathways of the steam flow. In summary, each of the goals for this project was achieved. The two thin reservoir units and the top sealing shale were resolved while inversions were very beneficial for reservoir characterization and understanding facies changes. The steam chest was easily discernable and its volume was calculated. These results justified the first ever 4DVSP in Kuwait which was acquired in January 2017. Ultimately, knowing where the steam fronts travel, where lateral barriers divert the steam, and how quickly it moves will help to optimize the development plans for the best possible EOR effectiveness and recovery rate improvement.
Proven Hydraulic Fracturing Field Applications for Real-Time Visualization and Monitoring System
Authors: Hlidek Barry T. , Lee Charlie 
Published: October 2017

Abstract
The confirmation of critical downhole events helps operators make effective real-time decisions during hydraulic fracturing operations. A relatively new monitoring system has been gaining traction in the industry, using high resolution pressure and acoustic signals to help operators visualize downhole and surface events. This paper briefly describes the real-time visualization system (RTVS) monitoring operation and focuses on case histories from the field.
Traditionally, downhole events such as fracturing sleeve shifts are verified by surface pressure signatures. Gaps may occur when conventional pressure signatures are ambiguous, if, for example, the bottomhole pressure is low. The monitoring system provides a visual and audible representation of downhole and wellhead events, using a unique and specialized array of electronic sensors. The monitoring system operates alongside conventional pressure measurement, as a separate and independent verification. The data stream can be integrated with conventional monitoring data.
Through a series of both onshore and offshore case histories, the system is proven to be able to confirm both pressure and non-pressure events. The paper includes detailed field examples utilizing the visualization system. Specific examples include determination of ball launches from the wellhead to confirm launch equipment and procedures. Fracturing sleeve operations can be verified, including balls seating and sleeves shifting. Failed ball launches at surface or unshifted sliding sleeves downhole can result in a costly loss of entire treatment stages or inadvertent overstimulation. Equally important are troubleshooting issues, which, if correctly diagnosed, allows the problem to be effectively addressed. Themonitoring system has detected equipment failure, including pump and casing breaches. Also, the paper will address limitations of the monitoring system; some types of events are not clearly identifiable.
The RTVS is deployed on surface, can be set up in 30 minutes, and has a small footprint. Real-time monitoring adds an extra layer of information, enabling better completion optimization, and reducing uncertainty and downtime. Continued data collection will provide theindustry with a better understanding of unseen events that will contribute tofuture operation and technology development.
Demonstration of Processing Capacity Enhancement on an Offshore Facility through Systematic Field Trials
Authors: Rodrigues Neil , Joshi Nikhil , Jagneaux Ricky L. , Kapadia Kashyap P. 
Published: October 2017

Abstract
The Constitution Spar is located in Green Canyon block 680 in the Gulf of Mexico, approximately 190 miles from New Orleans and in approximately 5,100 feet of water. The original nameplate separation capacity for the spar is 70,000 BOPD and 200 MMSCFD and production potential from future developments is expected to exceed this limit. In order to maximize the value to Anadarko and its partners, a systematic effort is underway to enhance the throughput of the facility.
The methodology includes evaluating all components of the subsea and topsides system for potential bottlenecks and identifying actions to remediate them. The overall goal is to utilize existing infrastructure to maximize production volumes with minimal investment into facility upgrades. One of the bottlenecks that was identified was the design capacity of the production separators. Separator designs are typically performed with little information on reservoir fluids and separation correlations do not always match field performance data. There is also very limited information available in the literature about improving separation efficiency in the field. Therefore, field tests were performed with the goals of identifying any deficiencies that would inhibit the facility from reaching nameplate capacity, as well as to identify areas of improvement that would allow the facility to processbeyond this limit.
The test as a whole was successful and the first and second production trains saw capacity increases of 23% and 32% respectively. All the separation Key Performance Indicators (KPIs) that were established prior to the test were met or exceeded due to rigorous management of the process conditions and chemical treatments.
In addition to the test results, the paper will include discussion on pre-planning, safety review, test design and real-time performance tracking, all of which were critical in order to ensure that the test objectives were met with minimal impact to facility uptime. There will also be discussion on specific separation challenges that were faced and actions taken to address them.
Dry Liquids on Silica as Secondary Emulsifiers for Drilling Mud Applications
Authors: Lifton V. , Gorka J. , Parrish D. , Davidson J. 
Published: October 2017

Abstract
This paper presents a systematic study of the performance of a family of "dry liquid" emulsifiers prepared via a novel "liquid-to-powder" process based on absorption of liquid by special types of synthetic amorphous silicas. The ability to use chemicals in solid form improves safety, handling, and ease of use. This process also avoids complications stemming from possible spills when using liquids, and the challenges of maintaining particular concentrations of the components normally affected by solvent evaporation.
Secondary emulsifiers are used in oil-based drilling fluids to enhance the performance of primary emulsifiers used to create a water-in-oil emulsion. In their native state these emulsifiers are high viscosity and high pour point liquids, which are normally difficult to dispense, especially in a cold environment. Secondary emulsifiers derived from canola fatty acid were investigated in this project and by using synthetic silica they were converted into "dry liquids". Silica used in the study were prepared by the precipitation process, with the structure required to absorb large volumes of liquids, immobilizing them in the internal pore volume in the typical weight ratio of 2:1 liquid-to-silica. The resulting freely-flowing powder can then be used "as is", and is not affected by the temperature or moisture in the environment.
The viscosity data shows that the "dry liquid" secondary emulsifier has performance equal to the "standard"liquid secondary emulsifier with no negative effects. The emulsion stability data suggests that the dry liquid secondary emulsifier maintains good electrical stability of the drilling mud. Overall, the data show that the secondary emulsifier has the same functionality in its natural liquid form and in the "dry liquid" form on silica carrier.
"Liquid-to-powder" method is a useful approach of converting challenging materials such as hygroscopic solids, viscous and freezable liquids into free-flowing powders for precise dosing and ease of handling. It expands the ability to create "dry" formulations based on the individual components absorbed onto inert silica carriers.
Seismic Inversion Based SRV and Reserves Estimation for Shale Plays
Authors: Sinha Saurabh , Marfurt Kurt J. , Devegowda Deepak , Pires de Lima Rafael , Verma Sumit 
Published: October 2017

Abstract
Estimation of stimulated rock volume (SRV) is the cornerstone offield development planning in shale reservoirs. The EUR has a first order dependency on the SRV and therefore its estimation is extremely critical for field development.
In this paper, we propose a methodology to estimate the SRV and hence the EUR for a shale reservoir using seismic data, flow and geomechanical simulation. The backbone of our methodology is seismic inversion coupled with geomechanical simulation. We apply our technique to data acquired from the Barnett shale.
In this work, we first use 3D seismic and sonic logs to perform pre-stack seismic inversion. Then, we derive the distribution of Poisson's ratio and Young's modulus in the area of interest (AOI). We constrain the porosity in our geo cellular model using a rock type model. Our rock type model for this work is based on k-means clustering on multi-well log analysis.
We modeled a well in the AOI for which microseismic data is available. Weused a coupledflow and geomechanical simulator to mimic the fracturing process and the fluid volumes injected during the actual completion of the well. For geomechanical coupling, we used Barton-Bandis model in seismic inversion-derived Young's modulus and Poisson's ratio 3D volumes. Next, we compare our results with the SRV obtained by an analysis of microseismic data. We reconcile differences in the model-derived SRV and then calibrate the resulting flow model and use the history-matched model for forecasting production.
Our results indicate an excellent match on SRV and therefore production data. Because we usevariable geomechanical parameters along the lateral, we observe irregular SRV's and drainage areas consistent with the microseismic data. Our methodology for predicting microseismic can be used for asset evaluation, acreage prioritization and to optimize the completion design in unconventional plays.
Innovations in Engineering Graduate Course Delivery for Oil and Gas Professionals
Authors: Goulis Kelly , Ershaghi Iraj 
Published: October 2017

Abstract
In today's exponentially changing technological landscape, the upgrading of skills and knowledge is of critical importance. Like in other professional fields, engineers, working in the oil and gas industry also need to pursue advanced degrees and to keep their skills up to date. For anyone working in the petroleum industry, partly because of the remote location of operations and in part because of frequent travel-associated assignments, the environment for pursuing advanced degrees may seem restrictive and impossible. Also, the nature of the oil and gas industry often requires professionals to work in locations away from major cities; often travel to remote locations and be away from their offices for a substantial period. This can be discouraging and make it impossible for these professionals to enroll in traditional on-campus educational degree programs. More importantly, even if located near a major metropolitan area, there may not be a credible or relevant local university program to provide the necessary education nor is there expectation to teach such graduate courses. Indeed, the desire to enhance professional qualifications and to acquire graduate education can rapidly diminish when there is limited access to the accredited educational providers. Added to that is a fear for getting involved but later facing roadblock in balancing work, family responsibilities and the intended educational program.
In recent years, an effective way to circumvent this obstacle has been relying on modern communication methods that enable access to accredited advanced education via high-quality Internet to the classroom regardless of individual's location. This breakthrough has provided a unique continuous learning opportunity for many engineering or science graduates in oil and gas professions and at various stages of their careers. But experience shows that the course delivery besides video communication needs other components to provide an inviting, effective and appealing virtual learning environment. We share experiences gained at the DEN@Viterbi system that has included many conveniences to the part time students1.
Aggressive Fracturing Treatments in Horizontal Wells: Benefits and Pitfalls
Authors: Daneshy Ali 
Published: October 2017

Abstract
The oil and gas industry has been successful in its use of trial-and-error as the main technique for enhancing the productivity of fracturing treatments in horizontal wells. The lower fracturing costs of the last three years have provided the impetus for moving in the direction of more aggressive treatments; much larger volumes of fluid and proppant, longer horizontal reaches and shorter spacing between adjacent fractures. In general, these changes are claimed to have improved the productivity of fractured horizontal wells, at least in the short term for which data has been available.
The justification for these changes requires assuming a different model of fracture propagation than is often assumed by the fracturing community. Closer examination of these treatments indicates that they implicitly assume a more planar fracture shape. Some of the existing data on pressure interaction between offset wells while fracturing shows incidents of fracture shadowing as well as frac/frac intersections. At times the observed data indicates low effective fracture conductivities, which is in-line with the practice of using more proppant. The relatively consistent fracture orientation within a single well and in multiple offset wells indicates larger difference between the two horizontal principal stresses than usually assumed within the fracturing technical community. This condition is needed for the success of the more aggressive treatments.
On the negative side, aggressive well and fracture spacing can increase fracture length and the likelihood of interference between fractures in adjacent wells. Taken too far, this can have significant impact on future reservoir development, including damaging the existing fractures, and production re-distribution between offset wells.
Collaborative Work Environment Implementation Strategy for Marginal Field Operators
Authors: Udofia Emmanuel , Obong Benjamin , Rui Ray Zhenhua 
Published: October 2017

Abstract
Collaborative Work Environment (CWE) is an operation integration concept supported by real-time systems (tools and facility), defined business processes and the right set of domain experts. The objectives in Collaborative Work Environment implementation includes; providing an operating asset the benefits of real-time operation optimisation and reduction in personnel unsafe travel exposure alongside effective team collaboration resulting in faster decision making using the intelligent oilfield capabilities. This paper assesses, hypothetically, the Collaborative Work Environment implementation strategy for a marginal field operator in Gulf of Guinea.
Collaborative Work Environment solutions are not really new to the oil and gas industry, as it has been widely implemented and embedded by major oil and gas companies in different regions around the world. However, what that is really novel are the challenges of implementation by marginal field operators. The challenges in implementing Collaborative Work Environment by marginal field operators includes; high-cost relative to the asset financial base and importantly the need for ‘visible’ benefit of intelligent oil field solutions linked to the business objective of the small operator. This paper aims to highlight an effective business strategy of implementing intelligent oil field by a marginal field operator by using procedure of comparing a case study during a well workover operation against standard implementation strategy by the major oil and gas companies.
The benefits of the Collaborative Work Environment were clearly ‘visible’ leveraging on the real-time support from the office to the field using the Collaborative Work Environment technology, facility and processes. The immediate ‘visible’ benefit of Collaborative Work Environment strategy during the well intervention operation included; faster team decision-making and situational awareness collaboration with remote location using intelligent oil field capabilities.
This experience provided a novel platform for developing an asset-specific intelligent oil field implementation and embedment strategy for the marginal field or small exploration and production operators in environment similar to the Gulf of Guinea. The recommendations from this paper will form a quick reference tool and assist in developing Collaborative Work Environment implementation and embedment strategy for small oil and gas field operators globally.
Circulation Subs and Their Impact on Downhole Hydraulics
Authors: Liu Gefei , McCormick John 
Published: October 2017

Abstract
Circulation subs are downhole tools designed to create an additional flowpath from the pipe to the annulus. The percentage of fluid that exits the string instead of traveling down to the bit or shoe depends not only on the size of the circulation sub ports, but also upon the density and rheology of the fluid, the flow rate, and the sub's position in the string.
This paper takes a thorough look at the variables that affect the percentage of fluid travelling the two flowpaths when using a circulation sub, along with their impact on pump pressure and equivalent circulating density (ECD). A description of the various common operations and uses of circulation subs are also discussed. The flow rate, circulation sub's position in the string, fluid density, fluid rheology, and total flow area out of the circulating sub were analyzed to determine the degree of flow split, pump pressure, and ECD changes.
Graphical representations of outputs are presented to illustrate the results of changing variables using circulating subs. The sensitivity of the flow split between fluid traveling down the string vs. into the annulus when the total flow area, depth of the circulation sub, flow rate, fluid viscosity, and density are discussed. These variables are also used to evaluate the impact on each other, with a focus on the resulting pump pressure and bottom hole ECD.
This paper seeks to disseminate information on the impact of an available tool on common downhole operations, variables which need to be understood to properly plan for these tools, and the appropriate methods for modeling using computer aided numerical analysis.
Adaptive Real-Time Machine Learning-Based Alarm System for Influx and Loss Detection
Authors: Unrau S. , Torrione P. 
Published: October 2017

Abstract
Unexpected influxes and losses pose a significant risk to rig personnel, the environment, and drilling efficiency. Influxes and losses typically manifest in the circulation system (e.g., as increases or decreases in flow and mud-volume) and other rig surface measurements. Automated, real-time interpretation of these drilling parameter traces is complicated by the highly variable and transient nature of the circulation system during normal drilling operations. As a result, the most commonly deployed automated alarm systems (e.g., fixed +/- bounds) have high false alarm rates, and are sometimes treated as unreliable by rig personnel. Recent advances in machine learning enable data-driven algorithms to identify anomalous behavior in real-time data traces, but until recently, the uptake of these algorithms has been hindered by driller's lack of trust in these automated systems, and the complexity of explaining why these so-called "intelligent" algorithms do (or don't) generate alarms in any given scenario. This paper documents a novel machine-learning algorithm framework for circulation system monitoring that was designed to maintain a very low false-alarm rate and earn the driller's trust by explicitly providing expected safe operating bounds on flow-out and pit-volume, so that even during long (e.g., 24-hour) periods without alarms, the driller knows that the system is operational and trustworthy. We present performance results generated across a massive body of drilling data that illustrate the trade-offs between detection rate and false alarm rate that are inherent to any machine learning (indeed, any algorithm) approach to event detection, and show how explicit bound generation can be used to improve driller trust and acceptance.
A Statistical Mechanics Model for PVT Behavior in Nanopores
Authors: Coskuner Y. B. , Yin X. , Ozkan E. 
Published: October 2017

Abstract
Recent studies on phase behavior in nanopore confinement reveal inconsistent and contradicting results about the shift of the phase diagram and critical point. This paper focuses on statistical mechanics and molecular simulation to model the PVT behavior in confinement. Grand Canonical Monte-Carlo simulation is used to observe the effect of confinement on phase behavior of pure methane in 2 nm. The model takes into consideration the effects of the intermolecular forces between fluid particles and between fluid particles and solid surface. Density of methane is obtained from simulations at different pressures under isothermal conditions to determine the phase transition point. Results are compared with the published studies and the differences are discussed. It is shown that the size of the simulation box significantly affects the results of molecular simulation. As a result, some of the conclusions drawn in the literature about the shift of the critical point are questioned.