bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Steam-Additive Processes With DTS/DAS Applications in Heavy Oil Reservoirs
Authors: Temizel Cenk , Irani Mazda , Ghannadi Sahar , Canbaz Celal Hakan , Moreno Raul , Bashtani Farzad , Basri Mustafa A. 
Published: September 2019

Abstract
DTS/DAS applications provide key advantages in surveillance and better understanding of both unconventional and thermal operations in terms of key attributes including but not limited to conformance, wellbore integrity in better spatial and temporal terms. This study investigates the effects of CO2 in enhancing the steamflood process while incremental benefits are achieved through improved monitoring of the steamflood injection process using DTS/DAS applications using a completely synthetic but realistic reservoir model.
A full-physics reservoir simulator is used to model the process. The technical and economic details of deployment of DTS/DAS as well as the steam-additive process are outlined in detail. Sensitivity study carried out on the model indicates the key attributes along with their significance. Athabasca bitumen properties are used. CO2 additive increases the steam chamber size but lowers the steam temperature while naptha/CO2 additives lower the viscosity, thus optimization study carried out the optimum operating levels of the additives not only in physical production/injection terms but also in terms of economics.
The results indicate better reservoir management with DTS/DAS applications compared to the base case and injection can be monitored and adjusted better with such tools. DTS/DAS applications prove useful not only in terms of production performance but also in terms of economics. Physical properties of CO2 and naptha outline that the two have different dominant modes of improving recovery with steam-only injection. CO2 increases the extent of the steam chamber while lowering the steam temperature significantly.
This study approaches the delicate process of additive use in steam processes while coupling the additional benefits of use of DTS/DAS applications in optimizing the recovery and the economics outlining the key attributes and the challenges and best practices in operations serving as a thorough reference for future applications.
Novel 3D Fluid Displacement Simulations Improve Cement Job Design and Planning in the Gulf of Mexico
Authors: Bogaerts Martin , Cardozo Jimena , Flamant Nicolas , Giam David , Villar Vitor , Lehr Justin 
Published: September 2019

Abstract
A key to achieving zonal isolation is the complete removal of drilling mud from the annular space between casing and formation and the replacement of the mud by an appropriately designed cement slurry. Although fluid displacement simulators have been available in the industry since the 1990s, a new-generation mud removal simulator has been introduced that provides new levels of details and accuracy. The simulator can be used for all types of wells, but it especially brings value to complex wells such as those found in deepwater Gulf of Mexico.
The new fluid displacement simulator comprises a stiff-string centralization model that accurately predicts the casing standoff in a 3D wellbore. It accounts for fluid mixing inside the drillpipe and casing while the fluid travels down the wellbore and includes a high-resolution annular displacement simulator that accounts for the 3D wellbore shape and solves for azimuthal and axial flows. Thanks to these three new features, the simulator generates highly accurate and reliable results with which the cement job design can be optimized, leading to a higher probability of meeting job objectives and achieving zonal isolation.
The new generation simulator was used to design and optimize cement jobs in the Gulf of Mexico with strict cement job objectives. The results of the simulator were compared to actual results of post-job wireline cement evaluations logs. The paper includes several case studies of deepwater and shallow water cement jobs in various complex wellbore configurations. Actual cement job data were used to rerun the simulator, and the results were compared with both the prejob cement design and the post-job evaluation logs. The comparison shows that the wireline evaluation results match the fluid displacement simulations very closely when using the stiff-string centralization model in combination with the new fluid displacement simulator, therefore confirming the accuracy of the model.
Using the new stiff-string casing centralization and 3D fluid displacement simulator throughout the early planning and design of the cement job allows for an improved cement job design. The simulations highlight possible challenges early in the planning of the cement job so that any required changes or contingencies can be prepared ahead of time, thus resulting in a cement job design that meets the planned objectives.
Tight Oil EOR through Inter-Fracture Gas Flooding within a Single Horizontal Well
Authors: Fu Xuebing , Bonifas Paul , Finley Andy , Lemaster Julia , He Zhiyong , Venepalli Kiran 
Published: September 2019

Abstract
Over the last decade, tight oil production has become significant with the success of horizontal drilling and hydraulic fracturing. However, the recovery factor of tight oil production remains very low and no standard secondary recovery method exists after primary depletion. We propose a new secondary recovery method: to use existing hydraulic fractures (every other fracture) in a horizontal well as gas injection and oil production sites to conduct inter-fracturegas flooding within a single well.
An ideal process of this method envisions a horizontal well centered in an enclosed reservoir, where the hydraulic fractures are evenly distributed along the well, parallel to each other. If the hydraulic fractures can be effectively isolated, and injection and production can be conducted through alternate fractures at the wellbore, then highly efficient flooding patterns can be created. Key questions include: Is there adequate injectivity and productivity in a sub-microdarcy reservoir?How far are the ideal reservoir conditions from reality?How difficult is it to isolate individual fractures within the wellbore?
In addressing these key questions, first, the success of a flooding process relies on reasonable injectivity and response time between the injector and producer – in this case the injector being one hydraulic fracture and the producer being an adjacent hydraulic fracture; both economical rates and reasonable communication time between adjacent fractures are demonstrated through analytical calculations and reservoir simulations in a typical well setting; nearly 100% recovery is achieved in the reservoir units between the fractures in a miscible flooding process. Second, actual reservoir conditions are incorporated in our study, focusing on direct fracture communications; the effects are demonstrated, and comparisons among different methods are made. Finally, potential challenges in operations are summarized and current technologies are reviewed; the gaps between the current settings and the required settings are demonstrated. Economic discussions are made, indicating positive scenarios with large tolerances.
With the rapid development of tight oil reservoirs, Enhanced Oil Recovery (EOR) technologies are urgently required to improve the recovery factor beyond primary depletion. An effective flooding process may be conducted if the hydraulic fractures can be used as injection and production ports. As a first attempt to envision an inter-fracture flooding process, key aspects are defined and examined, showing promising results. Inter-fracture gas flooding may become a standard secondary recovery technique for tight oil reservoirs and add significant reserves.
State of the Art of Flow Management for Frac Plug Drillout and Flowback
Authors: Potapenko Dmitriy , Theuveny Bertrand , Williams Ryan , Moncada Katharine , Campos Mario , Spesivtsev Pavel , Willberg Dean 
Published: September 2019

Abstract
Highly efficient multi-stage hydraulic fractured horizontal wellbores are the dominant completion method for many basins worldwide. One potential weakness of multi-stage hydraulic fracturing is that the later stages of the completion workflow – frac-plug drill out (FPDO) and flowback – cause large pressure fluctuations and transient flows through the perforation clusters that coincide with a period of low closure stress in the fractures. The proppant packs in the fractures during this period are fragile and prone to failure. Previously reported results show that flowback and initial production practices have a major impact on proppant production, maintenance and disposal costs and the subsequent well performance. In this paper the results from over 200 FPDO and flowback operations from the United States and Argentina are reviewed. These results show that maintaining a balanced flowrate during FPDO operations is critical for minimizing inadvertent damage to the hydraulic fracture network.
The FPDO flowrate balance is the difference between the coiled tubing injection and annular return flowrates. The magnitude and sign of the balance corresponds to the instantaneous flowrate through the open perforation clusters into or out of the hydraulic fracture network. A positive balance rate, or overbalance, injects fluid into the fracture system. A negative balance rate, or underbalance, produces stimulation or formation fluids from the fracture network. Sudden changes between these two regimes creates local flows that can be severe enough to flush large quantities of proppant out of the fractures. Our results show that high-frequency multiphase flowmeters simplify the process of maintaining balance (no inflow, no outflow). Furthermore, close monitoring of any imbalance that develops, and rapid control of the surface choke and injection rate, can provide for an efficient operation while protecting the integrity of the fracture system.
Early monitoring of flowback and production with a high frequency flowmeter was shown to be extremely useful technique for optimizing well productivity during well clean-up. This paper also shows how a dual energy gamma ray multiphase flowmeter successfully quantified proppant produced during FPDO and flowback. Examples of the dynamics of sand production are shown, as well as correlations to events of excessive underbalance conditions.
At the end of the paper we show that most of the highlighted problems can be solved through making changes to the well construction workflow and accounting for relationships between various well operations. Incorporation of this workflow enables early prediction of well performance issues and their efficient resolution.
The Importance of Integrating Subsurface Disciplines with Machine Learning when Predicting and Optimizing Well Performance – Case Study from the Spirit River Formation
Authors: Hirschmiller John , Biryukov Anton , Groulx Bertrand , Emmerson Brian , Quinell Scott 
Published: September 2019

Abstract
This machine learning study incorporates geoscience and engineering data to characterize which geological, reservoir and completion data contribute most significantly to well production performance. A better understanding of the key factors that predict well performance is essential in assessing the commercial viability of exploration and development, in the optimization of capital spending to increase rates of return, and in reserve and resource evaluations.
Machine learning models provide an objective, analytical means to interpret large, complex datasets. Generally, such models demand large databases of consistently evaluated data. As geological data is interpretive, often varying from one geologist to another, or from one pool to another, it can be difficult to incorporate geological data into regional machine learning models. Consequently, efforts to use machine learning in the oil and gas industry to predict well performance are often focused exclusively on engineering completion technology. However, this case study has utilized a regional geological Spirit River database with consistent petrophysical evaluation methodology across the entire play. This geological database is complemented with public completion and fracture data and production data to build predictive models using inputs from all subsurface disciplines.
Redundancies in the data were identified and removed. Features explaining a significant proportion of the variance in production were also removed if their effect was captured by more fundamental, correlated features that were more straightforward to interpret. The dataset was distilled to 13 key features providing predictions with a similar precision to those obtained using the full-featured dataset.
The thirteen features in this case study are a combination of geological, reservoir and completion data, underlining that an approach integrating both geoscience and engineering data is vital to predicting and optimizing well performance accurately for future wells.
Identification of Remaining Reserves Using Pulsed Neutron Logging for Pressure Determination Behind Casing in Mature Gas Condensate Reservoirs
Authors: Gray Russell , Smith Emma , Parsa Ali , Kim Yonghwee , Odusi Gbolahan 
Published: September 2019

Abstract
The identification of remaining reserves in mature fields is of importance to extend the field life and production life of existing wells. The Alwyn field in Quad 3 of the North Sea has been producing from the Statfjord Formation reservoirs since 1987. The initial production targeted discrete sand bodies that are separated by laterally extensive shales. The initial field pressure measurements indicated the presence of vertical barriers that have led to depleted pressures in produced intervals. Identification of present-day reservoir pressure in the gas condensate reservoirs was required to determine missed production potential within the Statfjord Formation sand bodies.
A candidate well was selected to estimate pressure behind casing by using an advanced analysis method. The method used pulsed neutron data and Monte Carlo stochastic simulation-based forward modelling to evaluate gas condensate reservoir depletion. Conventional thermal neutron capture cross section (Sigma) has low sensitivity to gas density variations, making it unable to detect reservoir pressure changes.
Effects of Confinement on Compositional Simulation in Shale Reservoirs with Thermodynamic Properties Upscaling from Pore- to Reservoir-Scale
Authors: Cui Xiaona , Song Kaoping , Yang Erlong , Jin Tianying , Huang Jingwei , Killough John , Dong Chi 
Published: September 2019

Abstract
The phase behavior shifts of hydrocarbons confined in nanopores have been extensively verified with experiments and molecular dynamics simulations. However, the impact of confinement on large-scale reservoir production is not fully understood. This work is to put forward a valid method to upscale the pore-scale fluid thermodynamic properties to the reservoir-scale and then incorporate it into our in-house compositional simulator to examine the effect of confinement on shale reservoir production.
Firstly, a pore-scale fluid phase behavior model is developed in terms of the pore type and pore size distribution (PSD) in the organic-rich shale reservoir using our modified Peng-Robinson equation of state (PR-C EOS) which is dependent on the size-ratio of fluid molecule dynamic diameter and the pore diameter. And the fluid composition distribution and PVT relation of fluids in each pore can be determined as the thermodynamic equilibria are achieved in the whole system. Results show that the initial fluid composition distribution is not uniform for different pore types and pore sizes. Due to the effect of confinement, heavier components are retained in the macropore, and lighter components are more liable to accumulate in the confined nanopores. Then an upscaled equation of state is put forward to model the fluid phase behavior at the reservoir-scale based on our modified PR-C EOS using a pore volume-weighted average method. This upscaled EOS is validated with the pore-scale fluid phase behavior simulation results and can be used for compositional simulation. Finally, two different reservoir fluids from the Eagle Ford organic-rich shale reservoir are simulated using our in-house compositional simulator to investigate the effect of confinement on production. In addition to the critical property shift which can be described by our upscaled PR-C EOS, capillary pressure is also taken into account into the compositional simulation. Results show that the capillary pressure has different effects on production in terms of the fluid type, leading to a lower producing Gas/Oil ratio (GOR) for black oil and a higher GOR for gas condensate. Critical property shift has a consistent effect on both the black oil and gas condensate, resulting in a lower GOR. It should be noted that the effect of capillary pressure on production is suppressed for both fluids with the shifted critical property.
PetroCup Training and Skill Testing Facility in Field Development and Production Management
Authors: Aslanyan Artur 
Published: September 2019

Abstract
The paper provides an overview of digital oilfield development experience gained by Nafta College [1] employing the complex PolyPlan asset simulator during a multi-year programme of PetroCup [2] interactive tournaments.
During the last few years, professional multi-disciplinary teams of 8 to 10 people from petroleum organisations based in various countries carried out few-days exercises on production and development of synthetic assets. In total, more than 20 petroleum companies, 10 petroleum service companies and 10 academic and research institutions have taken part in this programme.
PetroCup sessions had various team structures, digital reserves and regional economics to ensure realistic production conditions. Despite this variation, some statistical metrics highlight dominant trends in oilfield development strategies, including effective and ineffective ones. The results may attract interest from petroleum asset managers to assess the efficiency of corporate strategies and policies in field development planning and well and reservoir management, and eventually increase their performance.
The provided statistics are useful for managers of petroleum companies to assess the range, perspectives and value of production-related services. The PetroCup statistics can also be used by training centres and universities as an indicator of upstream trends and for maintaining the right focus in petroleum engineering curricula.
Feature Compensated Borehole Image Compression for Real-Time Logging While Drilling
Authors: Gelman Andriy , Maeso Carlos , Godet Vincent , Padin Exequiel , Tarrius Mathieu , Sun Yong , Auchere Jean-Christophe , A Adrian , Wibowo Vera , Shrivastava Chandramani 
Published: September 2019

Abstract
This paper presents a novel borehole image compression algorithm for real-time (RT) logging while drilling (LWD). The compression scheme is designed to optimize the critical information required for RT decision making at low telemetry bandwidths. In the proposed algorithm we estimate the structure of the image (i.e. the amplitude and phase shift of the dip) and modify the encoding dictionary based on the features. The resulting dictionary resembles sinusoidal features, thus optimizing the reconstruction of bedding or other planar features in deviated wells. The dictionary is designed using a modified version of the 2D discrete wavelet transform (DWT). This approach has a low encoding complexity and supports the integration of directional information into the transform. Since feature estimation is a challenging step, we use a classifier to identify when directional information should be added to the transform or whether a conventional implementation is used. The algorithm has been implemented in both oil- and water-based mud LWD imager tools, where the low encoding complexity has facilitated the implementation in legacy tools with limited computation resources. We present field test results comparing the borehole images from RT and recorded mode (RM) data from one of the industry’s first RT LWD resistivity images obtained from a well drilled using oil-based mud.
Tunable Friction Reducer Improves Operational Efficiency and Increases Production in the Eagle Ford
Authors: Luster Jared , De Sario Christine , Khan Shafeeq , Long Jeffrey 
Published: September 2019

Abstract
This study will demonstrate a comparison of completion fluid designs in operations and production across several pads in Gonzales and Lavaca counties in the Eagle Ford Basin. The use of tunable friction reducers (FRs) significantly improves completion efficiency and production. The paper also illustrates how tunable FRs provide greater versatility at the wellhead by replacing multiple fracturing fluid systems such as conventional friction reducer and linear gel with a single additive.
When conventional FRs prove inadequate in slickwater designs, subsequent HVFR and linear gel designs are utilized. This study demonstrates that tunable FRs provide the flexibility to be run at lower concentrations as an effective and efficient friction reducer. Should the slickwater treatment be insufficient, the FR concentration can easily be increased to achieve improved results for pressure reduction and sand placement while minimizing chemical additives and equipment on location. In addition, this tunable FR is engineered with breakable linkages that minimize formation damage to help improving production.
Tunable FRs can be run at less concentration compared to conventional FRs while delivering the same friction reduction as slickwater. Increasing the concentration produces a higher viscosity similar to that seen in linear gel. This flexibility is achieved with less equipment and additives and can be executed on- the-fly while pumping. This design has enabled an operator in the Eagle Ford to complete more stages with less shutdowns and screenouts. Eliminating equipment and extra additives simiplified logistics, reduced the footprint and equipment-related non-produtive time (NPT). Overall, production results taken over the first 12 months show that wells completed with the tunable FR had noticeably superior performance in cumulative production, which is normalized by lateral length. These improvements can be attributed to the proppant transport capabilities and the breakability of the tunable FR, which minimizes residue left in the formation and, in turn, provides greater regain conductivity.
Additional benefits include simplified delivery and smaller jobsite footprint requirements, which lead to significant cost savings. The tunability of the FR allows it to be administered on the fly while pumping, giving design change flexibility, enhancing overall operational efficiency. Since there is no need of hydration unit or dry-on-the-fly (DOTF) unit used for hybrid linear gel design, fewer NPT hours due to equipment breakdown was seen on location.