bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development and Application of Fast Simulation Based on the PSS Pressure as a Spatial Coordinate
Authors: Nakajima Kenta , King Michael 
Published: September 2021

Abstract
Recent studies have shown the utility of the Fast Marching Method and the Diffusive Time of Flight for the rapid simulation and analysis of Unconventional reservoirs, where the time scale for pressure transients are long and field developments are dominated by single well performance. We show that similar fast simulation and multi-well modeling approaches can be developed utilizing the PSS pressure as a spatial coordinate, providing an extension to both Conventional and Unconventional reservoir analysis.
We reformulate the multi-dimensional multi-phase flow equations using the PSS pressure drop as a spatial coordinate. Properties are obtained by coarsening and upscaling a fine scale 3D reservoir model, and are then used to obtain fast single well simulation models.
We also develop new 1D solutions to the Eikonal equation that are aligned with the PSS discretization, which better represent superposition and finite sized boundary effects than the original 3D Eikonal equation. These solutions allow the use of superposition to extend the single well results to multiple wells. The new solutions to the Eikonal equation more accurately represent multi-fracture interference for a horizontal MTFW well, the effects of strong heterogeneity, and finite reservoir extent than those obtained by the Fast Marching Method.
The new methodologies are validated against a series of increasingly heterogeneous synthetic examples, with vertical and horizontal wells. We find that the results are systematically more accurate than those based upon the Diffusive Time of Flight, especially as the wells are placed closer to the reservoir boundary or as heterogeneity increases.
The approach is applied to the Brugge benchmark study. We consider the history matching stage of the study and utilize the multi-well fast modeling approach to determine the rank quality of the 100+ static realizations provided in the benchmark dataset against historical data. The multi-well calculation uses superposition to obtain a direct calculation of the interaction of the rates and pressures of the wells without the need to explicitly solve flow equations within the reservoir model. The ranked realizations are then compared against full field simulation to demonstrate the significant reduction in simulation cost and the corresponding ability to explore the subsurface uncertainty more extensively.
We demonstrate two completely new methods for rapid reservoir analysis, based upon the use of the PSS pressure as a spatial coordinate. The first approach demonstrates the utility of rapid single well flow simulation, with improved accuracy compared to the use of the Diffusive Time of Flight. We are also able to reformulate and solve the Eikonal equation in these coordinates, giving a rapid analytic method of transient flow analysis for both single and multi-well modeling.
Making Workovers Easy and Cost Effective: Turning Old Ways into New Opportunities
Authors: Raza Mustansar , Elmoneim Hossam , Looten Kris , Elzanaty Omar , Shakeel Ahmed , Shehzad Kamil , Sarbast Mustafa , Yousif Serwer 
Published: September 2021

Abstract
A case study and methodology is presented to shed the light on the different processes followed during the placement of a non-damaging isolation barrier in a group of highly naturally-fractured and vugular gas wells. The temporary isolation aims at isolating the wellbore from the troublesome formation and allow the removal of the original completion string and install a new redesigned one. The process helped putting the wells back on production with-out the need to stimulate any of them. This helped client to reduce the overall workover cost by 40% and proved to be successful and efficient to complete the required operation in a time-efficient.
The operator had 4 wells with OH sections ranging from 40-80m which were completed in the late 1990's with no production packer. To preserve wellbore integrity the completion string needed to be pulled and replaced by a string with production packer and DH gauges. Visco-Elastic Surfactant (VES) and calcium CaCO3 (carbonate) used ubiquitously in field operations were tested for optimal design to fill highly fractured OH without damaging formation. Caliper logs were not available, and the presence of natural fractures posed a challenge to calculate the actual OH volume. A system was developed to carry the CaCO3 into the wellbore in stages and slickline was employed to measure fill after each stage. Once the OH was filled with CaCO3 and well would support a fluid column coil tubing was used to place an acid-soluble cement plug in the short interval between casing shoe and end of tubing (6-9m). The paper describes the optimization process followed to tune the CaCO3 pads composition, gel composition, mixing and placement technique.
The first well in the campaign required more than 10 times the theoretical volume of CaCO3 to fill the open hole with multiple settling issues at surface. It was concluded the surfactant gel was likely carrying the CaCO3 into the fractures. The procedure was modified to tie in a line of breaker solution to the well head allowing sufficient viscosity of the fluid to carry the CaCO3 from surface but immediately lose viscosity and allow the CaCO3 to settle in the open hole without being carried into the formation. Specific coil tubing procedures were employed to allow the setting of ultra-short acid soluble cement plugs (&lt;6m).
All wells were successfully isolated to allow the safe workover of the completion string and returned to production with no loss of gas flow, with-out the need to stimulate after the work over.
The campaign exhibited a new method of employing existing technologies to achieve the objective in a highly challenging and relatively new oilfield of Kurdistan. The campaign also demonstrated the benefit, in terms of saving time and cost because of extensive pre-execution planning.
Vertical Education Enhancement Approach to Meeting Emerging Skillset Needs in Oil and Gas Industry
Authors: Egarievwe Stephen U , Johnson Jamie A , Agbalagba Ezekiel O 
Published: September 2021

Abstract
Emerging technologies often bring new opportunities to enhance productivity and safety in the oil and gas industry. New technologies and opportunities often come with the challenges of workforce development to provide entry-level and current professionals with the necessary training and skillset. This paper presents a vertical education enhancement (VEE) model approach to providing emerging skillset needs in the oil and gas industry with emphases on curriculum continuous improvement and lifelong learning. The top new and emerging technologies that are critical to the future of the oil and gas industry in enhancing productivity and safety include Internet of Things (IoT), artificial intelligence, big data analytics, cloud computing, and 3D modeling/visualization. As part of the solution to train the oil and gas industry workforce to meet the challenges of adopting these technologies, the VEE model features a vertical education structure that encompasses outreach to K-12 education, recruitment, tertiary education, professional training, and lifelong learning. It has an interwoven fundamental structure consisting of curriculum and mentorship, partnerships with stakeholders (industry, government, and community), and research and funding. The VEE model has periodic assessment continuous improvement processes for identifying emerging technologies and new skillset needed to improve the workforce. These processes are like those practiced by accreditation bodies such Accreditation Board for Engineering and Technology (ABET), United Kingdom Accreditation Services (UKAS), and Offshore Petroleum Industry Training Organization (OPITO). Diversity to increase the participation of underrepresented minority groups and women in engineering would further increase the workforce. The novelty that the VEE model approach brings is the effectiveness in providing skillset training in new and emerging technologies for the oil and gas industry at all levels of workforce development. These include content infusion in existing courses, special-topic and specialized courses at senior and graduate levels, and professional development education and training through lifelong learning platforms.
A 20 Years Systemic Study of Drilling Practices in a Geothermal Venture Reveals Insightful Findings
Authors: AlMuhaideb Abdullah , Noynaert Sam 
Published: September 2021

Abstract
Geothermal drilling has increased in the recent years with the renewable energy initiatives. Geothermal plants provide more than 6% of California's electricity. A large sum from the development budget is consumed by the drilling. This paper systematically analyzes and reviews the drilling activities and operations in a geothermal venture in Hawaii for more than 20 years to enhance the drilling operations and save costs.
The paper starts by studying the geology of the area, which is located in an active volcanic region. Then, an extensive data collection was performed that went back to more than 20 years. The data was preprocessed and cleaned to be used in the analysis. The well designs were analyzed and the distribution of the drilling time was determined. After that, the performance of the geothermal drilling was benchmarked with the oil and gas drilling and the geothermal drilling in different parts around the world.
The geology of the area is challenging with basaltic formation and tectonic movements. Volcanic eruptions that leads to closing wells were encountered in the recent years. As for the drilling, six challenges were identified and deeply analyzed. These challenges include: lost circulation, stuck pipe, cementing, low rate of penetration (ROP), logistics issues, and safety concerns. Each of these challenges was intensely investigated and solutions were proposed. The benchmarking with the oil and gas industry and other geothermal drilling operations shows that the geothermal drilling operations can be enhanced significantly. This improvement in the drilling in the geothermal venture will result in huge cost savings.
A set of recommendations to improve the performance is presented as new organizational and workflow changes, analysis and elimination of nonproductive time (NPT), and novel engineering redesigns.
Determination of Methane Diffusion Coefficients in Live Oils for Tight Reservoirs at High Pressures
Authors: Yang Yibo , Regueira Teresa , Rodriguez Hilario Martin , Shapiro Alexander , Stenby Erling Halfdan , Yan Wei 
Published: September 2021

Abstract
Molecular diffusion plays a critical role in gas injection in tight reservoirs such as liquid-rich shale. Despite recent efforts on measuring diffusion coefficients at high pressures, there is a general lack of the diffusion coefficients in live oil systems at reservoir conditions relevant to the development of these tight reservoirs. The reported diffusion coefficients often differ in orders of magnitude, and there is no consensus on the reliability of the common correlations for liquid phase diffusion coefficients, such as the extended Sigmund correlation. We employed the constant volume diffusion method to measure the high-pressure diffusion coefficients in a newly designed high-pressure tube. The experimental method was first validated using methane + hexadecane and methane + decane, and then used to measure the methane diffusion coefficients in two live oils at reservoir conditions. The obtained data were processed by compositional simulation to determine the diffusion coefficients. The diffusion coefficients measured for methane + hexadecane and methane + decane are in agreement with the existing literature data. For methane + live oil systems, however, the diffusion coefficients estimated by the extended Sigmund correlation are much lower than the measured results. An over ten times adjustment is needed to best fit the pressure decay curves. A further check reveals that for live oil systems, the reduced densities are often in the extrapolated region of the original Sigmund model. The curve in this region of the extended Sigmund correlation has a weak experimental basis, which may be the reason for its large deviation. The estimates from other correlations like Wilke-Chang and Hayduk-Minhas also give very different results. We compared the diffusion coefficients in high-pressure oils reported in the literature, showing a large variation in the reported values. All these indicate the necessity for further study on accurate determination of high-pressure diffusion coefficients in live oils of relevance to shale and other tight reservoirs.
Real-Time Optimal Resource Allocation and Constraint Negotiation Applied to A Subsea Oil Production Network
Authors: Dirza Risvan , Skogestad Sigurd , Krishnamoorthy Dinesh 
Published: September 2021

Abstract
This paper considers the problem of steady-state optimal resource allocation in an industrial symbiotic oil production network, or in general, a large-scale oil production system network, where different organizations share common resources.
These allocation problems are typically solved in a distributed optimization framework, where the optimization problem is decomposed into smaller subproblems, a central coordinator is used to coordinate the different subproblems. However, the use of a central coordinator may introduce additional practical challenges, such as impartiality issues, or additional operating costs, which is undesirable even in the technological selection phase.
To eliminate the need for a central coordinator, this paper proposes a consensus-based optimal resource allocation, where each subproblem or organization is locally optimized, and the coupling constraints are negotiated among the different organizations over a fixed communication network with limited information exchange.
The proposed approach is applied to a large-scale subsea oil production system, where the different wells are operated by different organizations. The simulation results of the application show that the proposed approach can optimally allocate the shared resources.
Economic Evaluation of CO2 Capture, Transportation, and Storage Potentials in Oklahoma
Authors: DaneshFar J. , Nnamdi D. , Moghanloo R. G. , Ochie K. 
Published: September 2021

Abstract
Oklahoma is known for having ample sources of CO2, pipelines and sinks where for many decades, oil and gas operators were injecting CO2 into geological formations for EOR purposes. We utilized SimCCS, an economic-engineering software tool (DOE-NETL), to integrate infrastructure related to CO2 sources, pipeline, and geological formations. The approved tax incentive program by IRS (45Q) has motivated many oil and gas operators to participate in reducing CO2 concentration and minimizing global warming effect by collecting CO2 from various sources, select the best pipeline route and the safest location to inject into geological formation for EOR purpose or deep saline aquifer for sequestration.
This paper presents an economic evaluation of CO2 capture, utilization, storage (CCUS) into geological formation in the state of Oklahoma. Under this comprehensive approach, the process of capturing, transporting, and storing CO2 into geological or saline formations has been economically evaluated for different sites and routes utilizing an ad hoc simulation software (SimCCS) for integrated modeling of CCUS. The outcome of this paper determines the most optimal scenario using optimization algorithms embedded in SimCCS.
This case study will mitigate the CO2 sequestration approval process when operator apply for tax credit under 45Q program. Our work will assist oil and gas operators by comparing different scenarios based on utilizing existing infrastructure, making decision in building new transportation system or new injection well to benefit the approved tax incentive program at its maximum capacity. Moreover, the outcome of this work will shed lights into future legislation demands (locally and nation-wide) to maintain CCUS momentum after its initial implementation phase is concluded.
Effect of Inter-Particle Van Der Waals Attraction on the Stability of Pickering Emulsions in Brine
Authors: Hatchell Daniel , Song Wen , Daigle Hugh 
Published: September 2021

Abstract
Pickering emulsions are stabilized by solid particles that occupy the fluid-fluid interface, physically preventing coalescence. Their stability in brine, where interparticle electrostatic repulsion is negligible and van der Waals (vdW) attraction dominates, makes them attractive for applications in porous media. Recent studies postulate that inter-droplet particle networks assemble in brine and aid Pickering emulsion stability to coalescence. This work experimentally assesses the effect of increasing interparticle vdW attraction on particle network strength and emulsion stability.
We grafted 6 nm, 12 nm, and 20 nm silica nanoparticles with varying densities of polyethylene glycol (PEG) to prevent aggregation and dispersed them in either brine or deionized water (DI). We characterized the PEG-coated nanoparticles with thermogravimetric analysis and dynamic light scattering to determine PEG grafting density, diameter, and zeta potential. To generate oil-in-water emulsions, we sonicated dispersions of variable nanoparticle concentration and decane in equal volumes. We imaged the emulsions with microscopy and centrifuged them for 15 minutes at 5000 g of acceleration, using the volume of decane released after centrifugation as a measurement of emulsion coalescence to the applied force.
Nanoparticle characterization confirmed successful grafting of PEG to the silica surface. We compared trends in emulsion stability as a function of salinity and particle diameter to changes in the relevant interparticle forces described by extended Derjaguin-Landau-Verwey-Overbeek (DLVO) theory. Analysis of microscopy images showed an increase in emulsion droplet diameter with decreasing nanoparticle concentration, salinity, and increasing nanoparticle diameter. Through centrifugation we observed that lower PEG grafting densities tended to produce more stable emulsions, suggesting that particles with high grafting densities and consequently high steric repulsion tended to repel and prevent formation of strong particle networks. Emulsions generated in DI coalesced more easily, indicating that electrostatic repulsion dominated relative to vdW attraction and that particle networks did not form. In brine, where electrostatic forces were screened out by counterions, the emulsions better resisted coalescence, consistent with the formation of a particle network. The strength of the network was inferred from the difference in emulsion stability to coalescence in DI and in brine. We measured a greater brine-DI stability difference of 3.7× for the larger 20 nm PEG-coated nanoparticles, compared with 3.3× and 2.2× for the 12 nm and 6 nm PEG-coated particles, respectively, further supporting the role of particle networks on emulsion stability.
Efficient Water Softening for Avoidance of Scales in Heavy Oil Steam Floods
Authors: Prakash Prakhar , Concienne Reid , Demayo Trevor , Towne Kirsten 
Published: September 2021

Abstract
Pigging of Once Through Steam Generators (OTSGs) indicated various types of scales, the most predominant of these being silicates of hardness causing ions. It was noted that scaling propensity can potentially go up with higher Steam Quality (SQ) as the reject stream gets concentrated with ions. However, models suggested that there are benefits of higher SQ in enhancing fuel savings (8%) and electricity savings (2%) when SQ was increased by 20%. The challenges of higher SQ were noted in terms of increased scaling tendency and therefore the need for improved softening. In Field D, the service cycle, the backwash cycle, and the brining cycle were optimized leading to a gain in throughput and reduction in salt consumption. Service cycle improvement gained 30 % to 130 % in throughput between two regenerations, backwash cycle improvement by fluidizing the bed to nearly 35% helped gain 10% in throughput, and reduction of brining cycle from 75 minutes to 48 minutes helped reduce salt consumption by 56% without impacting the throughput. In Field B, a six month pilot revealed that shallow shell resins where ion-exchange is more efficient due to inert core (better intra particle diffusion control) can enhance the throughput by 30% - 80% and simultaneously reduce the number of regenerations by 15 – 30%. Resin fouling is still a major challenge to contend with as oil can foul the resin and throughput can decline by 0.5 – 3 folds. In a plant operation, where there are multiple softener and brine vessels, there is a need to optimize them as a system. Reliability, Availability, and Maintainability (RAM) Models are used in Field C to a) Address equipment configuration optimization with impact on capital capacity expansion project scope b) Understand how net softwater delivery capacity was affected by increases in inlet hardness and c) Assess through a comparison scenario, if the large cost of addressing the valve issue in an upstream nutshell filter was worth the lost production opportunity related to unplanned downtime.
Aplicability of an Innovative and Light Seismic Approach to Monitor SAGD Operations in Surmont: A Blind Test
Authors: Brun Victoria , Morgan Elodie , Gerl Brad , Cardozo Luis , Batias Jeremie 
Published: September 2021

Abstract
Surmont is a heavy oil field located in northeast Alberta which is currently being developed by a joint venture between ConocoPhillips and Total using Steam Assisted Gravity Drainage (SAGD). To monitor the enhanced oil recovery process and caprock integrity, highly repeatable 4D seismic surveys using dynamite have been completed over the years. In order to maximize the value of information while controlling costs, a novel light seismic monitoring approach has been "blind-tested" on existing 4D data.
The concept requires the use of only one source and one receiver couple, optimally placed in the field to monitor one or several subsurface spots, using time redundancy to detect 4D changes in these zones of interest. Three spot locations have been defined by the client on a well pad for which the history was not provided. For each of these spots, specific series of seismic processing steps have enabled the identification of the optimum source/receiver locations. Then, these optimum raw seismic traces extracted from different 4D campaigns have been analysed to detect potential time shift changes in the selected horizon induced by the growth of the steam chamber.
Time-shift changes were plotted for all 3 spots. An increase was observed for one of the spots (Spot 3) from the first 4D monitor in 2010 up to the last monitor in 2015. An increase was also plotted between March 2013 and September 2013 for another spot (Spot 1), changes attributed to the dynamics of the steam chamber. On the contrary, spot 1 did not see any effect of the steam. These time-shift changes were then successfully cross-checked with temperature data from observation wells, confirming the qualitative variations attributed to the effects of the steam chamber evolution.
It demonstrated the viability of this innovative seismic and focused monitoring approach to monitor the evolution of the steam chamber in Surmont. This also paves the way for a simpler and yet reliable and cost-effective way of monitoring the evolution of the steam chamber to further optimize production and increase rentability.