bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Transvers and Longitudinal Fractures Using Simulation and Well Deliverability Provides Optimal Completion Scenario for Improved Production in Gas Reservoirs
Authors: Rahim Zillur , Al-Kanaan Adnan A. , Soliman M. Y. , Pacheco Eduardo 
Published: September 2016

Abstract
Multistage fracturing (MSF) of horizontal wells has proven very successful in the development of moderate to tight gas reservoirs. To make MSF treatments fully successful, the well configuration must be carefully designed. One important point to consider is the direction of well azimuth. Since the induced fractures always propagate in the direction of maximum in-situ stress (σmax) direction, drilling wells towards the minimum stress (σmin) will generate transverse fractures. This scenario allows multiple independent fractures as there is no overlap between fractures. When a well is drilled along the maximum stress direction, the fractures propagate along the wellbore axis. In such case one fracture can overlap the adjacent fracture and thereby the number of independent fractures will be fewer.
Wells with transverse fractures are usually the first option in low-permeability shale, sandstone, and carbonate formations. This is because the reservoir to wellbore contact area is significantly increased as the number of fractures induced is increased. Many authors, however, have reported that in sandstone reservoirs, the efficiency of transverse fractures are affected by proppant pack permeability reduction attributed to non-Darcy flow. This study focuses on the best completion option for gas wells in terms of production performance and logistics to help ensure optimal field development.
Nanomaterials-Enhanced High-Temperature Fracturing Fluids Prepared with Untreated Seawater
Authors: Li Leiming , Al-Muntasheri Ghaithan A. , Liang Feng 
Published: September 2016

Abstract
Demand for water used in hydraulic fracturing is increasing continuously due to the implementation of oilfield technologies such as horizontal wells and multistage hydraulic fracturing. The rising cost of fresh water has motivated services and production companies to try to prepare fracturing fluids with less ideal water sources such as produced water and seawater.
Technically it is not too difficult to make fracturing fluids for medium-to-low temperature applications using salt water like produced water or seawater. However at high temperatures of, for example, 300°F or more, it is much more challenging to formulate stable fluids directly with untreated salt water due to the damages related to the high levels of salinity and hardness in the water. With innovative approaches and careful selections of fluid additives in our tests, potential fluid issues caused by low water quality and harsh downhole temperatures were resolved or mitigated.
A novel high-temperature fracturing fluid system was invented recently that could be prepared with untreated seawater having a TDS of, for example, about 57,000 mg/L. The fluids comprised of metal-crosslinked polysaccharide polymers, and remained stable at high temperatures of 300°F or more. In a typical test, the fluid viscosity stayed above 500cP (at 40/s shear rate) for at least 60 minutes at 300°F. The fluid stability could be further enhanced with the addition of a number of selected nanomaterials. For instance, when one of the nanomaterials was added to the above fluids at a dose of 0.02% by weight or less, the lifetime of the fluid viscosity above 500cP was extended by at least 30%. Tests also showed that, with the addition of the nanomaterials, the viscosity lifetime could remain the same even when the polymer loading was reduced. The fracturing fluids also consistently showed over 90% regained permeability in both coreflow and proppant pack conductivity tests. Overall, the novel seawater-based fluid system shows excellent high-temperature stability, minimum formation and proppant pack damage, and intrinsically low scaling tendency.
The synergetic behaviors among the fluid additives and the nanomaterials in the high-temperature fracturing fluids prepared with the untreated seawater will be discussed, and the field-related laboratory test results will be presented in detail.
Surface Web Balance Method A Neural Network-Based Approach to Mitigate Subsidence in Diatomites coupling Surface Deformation and Injection/Production Data
Authors: Temizel Cenk , Tiwari Aditya , Aktas Sinem , Putra Dike , Suhag Anuj , Kirmaci Harun , Balaji Karthik , Ranjith Rahul , Tahir Sofiane , Aminzadeh Fred , Yegin Cengiz 
Published: September 2016

Abstract
Diatomites are high-porosity, low-permeability reservoirs with elastoplastic properties and high geo-mechanical responsiveness. Despite that, diatomites have great potential for oil recovery. Withdrawal of fluids from the reservoir rock leads to subsidence causing compaction and shear stresses. This disturbed stress distribution results in well failures that causes loss of millions of dollars. Successful maintenance of pressure support through optimum injection/production is key to preventing subsidence to mitigate the risk of well failure and achieve better sweep efficiency for recovery.
There have been different approaches to tackle subsidence and well failures in diatomites including the use of ‘backpressure method’ coupled with a neural network to optimize injection-production to ‘balance’ the rock in terms of stress-distribution and thus decrease well failure due to shearing. However, using such methods may mask other problems the well is experiencing, such as, mechanical issues that influence production. Another existing approach, satellite-imaging (InSAR) cannot be used to take real-time actions that is crucial in diatomites.
Surface tiltmeter data is collected to undertsand the relationship between injection/production and resulting surface deformation, which also provides information about well-to-well connectivity. A neural network-based approach is followed to determine the nonlinear relationship between surface subsidence/dilation and injection-production. This is then used to build an objective function that works to minimize the differences between well-to-well subsidence/dilation measured by the tiltmeters, by adjusting injection-production for the wells.
In this paper, a method that harnesses real-time surface tiltmeter data to adjust injection-production distribution in diatomites to decrease well failures is used beyond the existing applications of surface tiltmeter, such as, in the areas of detection of early steam breach to surface in steam operations and fracture orientation and it provides real-time data for robust reservoir management of such reservoirs where satellite imaging is not effective.
Production Well Testing of Challenging Wells with an Enhanced Multiphase Flowmeter
Authors: Safar Emad , Karacali Ozgur , Al-Kanderi Ibraheem , Fuentes Escolastico Galvis , Acar Cagdas , Alshammasi Hussain 
Published: September 2016

Abstract
Production well testing is of paramount significance for building reliable production history of oilfields. Kuwait Oil Company (KOC) requires periodic testing of oilfield wells for production, pressure, and fluid property monitoring. In some cases, accurate flow-rate measurements cannot be conducted with conventional well test separators because flow rates are out of the operating range of the individual singlephase metering devices, challenging flow conditions (geometries) exist, or wells are flowing under non- critical conditions in which backpressure from the test separators or production lines affects well productivity. Typically, production well testing operations have been executed with portable testing units instrumented with multiphase flowmeters (MPFMs) or conventional test separators.
A recently introduced mobile dual-leg MPFM unit with 19- and 40-mm venturi sizes (installed side by side) in a single skid was used for the first time in several KOC wells together with other locations in the world. Dual venturi-size setup enables flow metering of a wider range of flow rates and provides enhanced phase fraction measurements via full gamma-ray spectrum analysis. We discuss the results of the well tests conducted with this recently introduced dual-leg MPFM and compare results with well test results obtained with other measurement devices and techniques.
The field test wells chosen comprise high and low flow-rate production wells that have various typical flow conditions (sluggy, stable, and emulsion-prone) and are representative of both natural producers and artificial-lift wells. Enhancements in operating principles of the dual-leg MPFM results in efficiency gains and test results are comparable to previous test results across the range of operations. Also, the well test results compare favorably with the pressure/volume/temperature (PVT) properties of the reservoir fluids as well as with manual measurements taken during the test, such as water cut, or basic sediment and water (BS&W) data.
The dual-leg MPFM provides an optimal solution for flow metering in oilfields and is ideal for daily mobile production testing operations.
A Novel Technique for Generation of Accurate Capillary Pressure Pc Curves from Conventional Logs and Routine Core Data and New Pc Endpoint Functions after Considering the Sedimentary Environment and Pore Throat Size Distribution Shape PTSDS
Authors: FazelAlavi Mohsen , FazelAlavi Mina , FazelAlavi Maryam 
Published: September 2016

Abstract
This paper presents an innovative method for derivation of Pc curves from log saturations, introduces better relations for end points of Pc curves and a better model for Pc curves. The influence of sedimentary and diagenesis environment on PTSDS and the effect of PTSDS on Pc curves are discussed and considered. This paper presents distinctive Pc models for diverse geologic zones. Examples demonstrate the improved accuracy using the proposed procedures.
This paper also discusses the classification of reservoir rock based on a distinct and specific linear relationship that exists between Flow Zone Index (FZI) and 1/ (Swir.φ) in a geological zone. This classification separates zones that have similar geology or PTSDS. Functions for entry pressure (Pe) and irreducible water saturation (Swir) in each class are found and a Pc curve model is constructed for each class. In the absence of good SCAL data, Pc models are generated from log saturations and routine core analysis data. Pc models provide Pc curves for all saturation regions in the reservoir model.
Reservoir rock classification is crucial for Pc curve generation. End points of Pc curves that are Pe and Swir depend both on PTSDS and other rock properties such as permeability (k), Flow Zone Index (FZI), Hydraulic Units (HUs), or reservoir quality index (RQI). In addition, PTSDS influences the shape of Pc curves. This research investigated correlations of Swir with k, FZI, HUs, and RQI and determined a) that these correlations are improved after classification and b) that, by inference, the strongest correlations exist when Swir is correlated to RQI and next to k. However, inferior correlations exist when Swir is correlated to FZI and HUs. Pe is also best related to RQI. Pc curves and reservoir saturations are markedly improved when the proposed classification is completed, end points are correlated to RQI, and the proposed model is used. Finally, very accurate Pc curves can be derived from log saturations when routine core data are available in a key well. The Pc model based on routine core data and log replicates log saturations in all wells perfectly. This method can eliminate the need for Pc curve measurement in the lab or reduce the number of required measurements.
Rock classification before Pc generation is necessary and crucial but is often ignored. The use of novel functions for end points of Pc curves and the proposed model for Pc curves results in a marked improvement in the accuracy of Pc curves. A novel technique that generates very accurate Pc curves from log saturations is introduced. This method can eliminate the need for and the cost of Pc measurement in the lab or reduce the costs. The result is greatly more accurate saturation modeling of the reservoir at lower cost.
Pore Scale Investigation of Wettability Effect on Waterflood Performance
Authors: Mohammadmoradi Peyman , Kantzas Apostolos 
Published: September 2016

Abstract
A direct quasi-static pore-scale modeling approach is implemented in a simulation package to reconstruct interfacial areas and predict two-phase fluid occupancy profiles during drainage and imbibition at low capillary number equilibria. The proposed pixel-wised algorithm is equipped by a novel object-based up-scaling methodology and is applied to three-dimensional consolidated and unconsolidated pore-level domains with uniform and non-uniform contact angle distributions. Stationary finite element simulations are conducted in partially saturated microstructures to provide the electrical and hydraulic conductivity predictions. The post-processing results present capillary pressure and relative permeability curves and the ad hoc parameters of Archie's law including tortuosity and formation factors, and cementation and saturation exponents. The data gathered in this study highlights the significant role of wettability in shaping the electrical and fluid flow pathways and reveals the impacts of cementation, rock configuration, conductive phase saturation, and two-phase spatial distributions on the flow of electric charges and petrophysical description of geological formations.
A Comprehensive Approach to Measure the RealTime Data Quality Using Key Performance Indicators
Authors: Otalvora William Contreras , AlKhudiri Musab , Alsanie Faisal , Mathew Binil 
Published: September 2016

Abstract
After the setup of a real-time drilling data feed from the Rig site to the operations center, the obvious question is - How good is the data that is being streamed?
Real-Time rig sensor data could be an effective input for drilling optimization, However, the confidence in the results of these analysis or interpretations is directly associated to the trustworthiness of the data acquired. Measuring the quality of the data has been a difficult issue for many years.
This paper shows the approach used by a large oil & gas operator to measure the quality of the information received from the rig providers, which is obtained from the sensors installed on every rig.
The Real Time Data Quality is measured by analyzing six different parameters: completeness, uniformity, sensibility, resolution, structure and format. The combination of these six indexes provides a deep understanding of the level of the quality of the data received, as well as the elements to be improved. Various KPIs including Footage KPI, Data QC Availability and Data QC Channels, are generated by the powerful engine of Automated Rig Activity Measurement (ARAM) to check the data quality of different vendors. Starting from having a check on data availability, these KPI's are capable of analyzing every row of time based data in real-time.
Data generated by a proprietary system for these KPI's is also being used in a Real Time Data Quality Dashboard. This measurement provides the drilling engineers with a systematic way to filter analysis results based on data of poor quality by specifying their acceptable data quality range. This daily analysis also allows the operator to identify Rigs that are performing better and rigs that needs to be pushed for higher quality data.
A New Modeling Approach to Optimize Methane-Propane Injection in a Field After CHOPS
Authors: Soh Ye Ji , Rangriz-Shokri Alireza , Babadagli Tayfun 
Published: September 2016

Abstract
Although cold heavy oil production with sands (CHOPS) is an economically attractive method, ultimate recovery does not exceed 10%. Cyclic solvent injection (CSI) has been under consideration as a follow-up EOR application in the industry. This method targets extracting large amounts of remaining oil in the matrix by solvent diffusion, taking advantage of its high contact area with wormholes. Methane and propane are two potential solvents to be used in this practice. Methane is preferred due to its availability and stronger foaming characteristics while propane has lower foaming but better mixing capability.
A far-reaching -core to field scale- study was conducted in this paper to test out the potential of pure methane and its mixture with propane as prospective CSI solvents. A 1.5 m long and 5 cm diameter sand-pack was initially saturated with brine. Then, live oil (saturated with methane and methane-propane mixture at different ratios) was transferred to drain the brine out. Typical field scale pressure decline rates were applied and pressure was monitored through eight equally spaced transducers placed onto the core holder. The experimental data from core and PVT tests were matched to a core scale simulation model to obtain K-values. These data were carried to a field scale model to analyze the CSI performance for methane and methane-propane mixture. In field scale modeling, 15-well data from CHOPS field from Alberta, Canada were history matched and 6-cycle CSI performances were followed as post-CHOPS with different well patterns (central, peripheral, all-wells).
As a result of these experiments, methane showed about 14% oil recovery, but with additional CO2 huff ‘n’ puff around 15% recovery was added, totaling 29% recovery. Methane-propane mixture resulted in a lower oil recovery, which was about 5%, due to decreased foamy effect. Valid core-scale simulation was completed by tuning K-values and considering non-equilibrium or equilibrium impact depending on solvent type, showing mostly less than 5% error. In field scale modeling, central and peripheral well patterns yielded oil recoveries consistent with the experiments while all-well huff ‘n’ puff- type pattern showed a slightly higher value.
Effect of Dynamic Active Fracture Interaction DAFI on Activation of Natural Fractures in Horizontal Wells
Authors: Daneshy Ali 
Published: September 2016

Abstract
Activation of natural fractures is generally assumed to be a major contributor to the productivity of unconventional reservoirs completed by creation of many fractures in horizontal wells. These natural fractures are assumed to form an interconnected high permeability network that shortens the length of the flow path and facilitates higher flow rates from the reservoir.
This paper reviews activation of the natural fractures that lie in the formation adjacent to, or in between, hydraulic fractures, but not directly connected to them. The solution uses the Mohr-Coulomb failure criterion and general equations for stress distribution around a hydraulic fracture.
The paper shows that under favorable conditions the stresses induced by the growing hydraulic fracture can activate existing natural fractures by either tensile or shear failure. Natural fractures close to the hydraulic fracture have the best chance for limited tensile activation. This type of activation is insensitive to differences between the original in-situ principal stresses. Activation by shear sliding is more likely to happen in cases of larger difference between the in-situ principal stresses and, again, will be of limited extent.
Hydraulic fracture conditions that increase probability of natural fracture activation are higher extension pressure, and proximity to the natural fracture. Natural fractures farther away from the wellbore have a better chance of activation if they fall within the influence zone of a long hydraulic fracture.
Activation of natural fractures by tensile stresses may create a zone of formation dilation and enhanced permeability around the hydraulic fracture. This increases the productivity of the hydraulic fracture and the reservoir.
Creation of a single hydraulic fracture is more likely to activate natural fractures than two or more concurrent fractures. The zone of activated natural fractures will also be larger. Increased normal stresses caused by creation of multiple concurrent fractures can actually close or narrow natural fractures that have already existed within the formation between these fractures.
Shorter spacing between adjacent hydraulic fractures can increase the percentage of the formation volume between them that contains activated natural fractures.
Improved Saturation Mapping Using Planar Tranmission Lines and Magnetic Agents
Authors: Servin Jesus M. , Schmidt Howard K. , Ellis Erika S. 
Published: September 2016

Abstract
The ability to accurately map injected seawater in waterflood operations is an essential goal of reservoir monitoring. This capability improves reservoir management practices by helping to delineate the oil-water interface in new wells, locate bypassed oil pockets, minimizing water fingering and proactively enabling identification of early water breakthrough events. Our approach involves loading the injected water with magnetic nanoparticles, called Magnetic NanoMappers (MNMs) to function as electromagnetic (EM) contrast agents. Detection is accomplished by EM means, similar to cross-well and borehole-to-surface EM imaging, but at higher frequencies. The strategy for developing this technology focuses on forward modeling and travel-time tomographic inversion software. We have previously shown in the laboratory — using a reservoir model — that MNMs slow the group velocity of transiting EM signals [1]. Our results demonstrated the capability of imaging targets filled with different fluids, with high resolution using EM means, which supports the idea of high resolution saturation mapping using MNMs. This paper proposes a novel method to address the challenge of long range EM propagation in the reservoir, in the presence of conductive media.
The proposed method relies on the use of natural planar transmission lines present in the carbonate reservoirs of the GCC area. An EM pulse traveling through a relatively non-conductive layer between two more conductive layers, will propagate with relatively low attenuation, and the pulse's travel time will depend upon the electromagnetic properties of the layers above and below. MNMs will provide velocity contrast for EM pulses traveling through regions of the reservoir saturated with MNMs-loaded injection water. Similarly, changes in oil and water saturation will result in changes in travel time. By performing full waveform inversion one would be able to produce a saturation map with higher resolution than conventional cross-well EM methods.
This paper details a series of Finite Element Method (FEM) simulations to investigate the feasibility of the proposed method. The results show that long range EM propagation can be achieved through non-conductive layers, acting as planar transmission lines. In addition, the results show that the pulses are modulated by the EM properties of the layers above and below the transmission line. These results open up a new possibility for long range high resolution saturation mapping using EM means.