bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Cased-Hole Porosity Measurement for a Four-Detector Pulsed-Neutron Logging Tool
Authors: Schmid Gregory , Pemper Richard , Dolliver Darrell , Mekic Natasa , Musselman Jon 
Published: September 2019

Abstract
A new cased-hole porosity measurement has been developed for a four-detector pulsed-neutron logging tool. The measurement is based on a capture count rate ratio from two different detectors. To determine an accurate porosity, the ratio is characterized in the laboratory in order to establish a ratio-to-porosity transform. To account for varying measurement conditions in the field, environmental corrections, based on laboratory studies and computer simulation, are applied. As an alternative to environmental corrections, the capture ratio can also be actively compensated for the environment by using the results of a dual-exponential fit to the capture time decay spectrum. In particular, we can compensate for the borehole fluid salinity by using the borehole component of the dual-exponential fit, and we can compensate for the effective density of the borehole environment by using an inelastic ratio derived from the capture subtracted burst yields. The final porosity measurement has been shown to provide accurate results in the field through a comparison with data from open-hole logs.
Simplified Dark Data Analytics of Everyday Completions Data, and its Relation to Observed Induced Seismicity Events: An Unconventional Big Data Solution
Authors: Qiu Yusheng , Adams Matthew , Grasselli Giovanni 
Published: September 2019

Abstract
Diagnostic fracture injection tests (DFIT's), or "mini-fracs" are often used to gauge many reservoir and fracture design parameters. However, DFITs are not always conducted in conjunction with the main completions work. This paper proposes a novel workflow to determine the instantaneous shut-in pressure (ISIP) from readily available completions data. This is a valuable parameter in itself as related to the least principal in-situ stress states as demonstrated by the stress change relationships near faults in Lavoie et al. (2018).
Directly using completions data from fracture stimulation operations, the authors have leveraged on the water-hammer signature in bottom-hole pressure data during completions to process the ISIP for each completions stage. Within this study, completions data from ~2100 stages from ~300 horizontal Montney formation wells were analyzed. A MATLAB script was used to automate the derived ISIP stress trends over the Montney formation and to deduce the ISIP in a consistent format.
This novel workflow also validates the expected in-situ stress trends at depth, with a relationship of high ISIP gradients closer to fault zones similar to stress change behaviour as shown in Lavoie et al. (2018). Specifically, a positive spatial relationship was observed pertaining to local ISIP gradients, the lithostatic gradient, the minimum in-situ stress, and the propagation of hydraulic fractures that are prone to reactivation of critically stressed faults. Based on our real-time observations, field operators may allow to flowback a well for a short amount of time to deplete the anthropogenic reservoir pressure and stress shadowing prior to resuming fracture stimulation.
Considering the continued push for higher fluid and sand loading in industry in the development of unconventional assets as an economic driver, there also exists a large and tangible corporate citizenship opportunity of mining real time completions dark data with the possibility of relating that live feed as a prescriptive tool to mitigate reactivation of critically stressed faults. This case study focuses on the Montney formation as a basis for processing easily available data from standard operations in an effort of systematically designating areas prone to seismicity risk in future hydraulic fracturing operations based on automated real-time analytics of dark data.
Application of Assisted History Matching to Unconventional Assets
Authors: Al-Rukabi Muhammed , Forouzanfar Fahim 
Published: September 2019

Abstract
Characterization of key parameters in unconventional assets continues to be challenging due to the geologic heterogeneity of such resources and the uncertainty associated with fracture geometry in stimulated rock. Limited data and the accelerating pace of asset development in plays like the Permian present an increasing need for an efficient and robust assisted history matching methodology that produces better insights for asset development planning decisions, e.g. well spacing.
A multi-scenario approach is presented to build an ensemble of history matched models that take into account existing uncertainty in reservoir description and well completions. We discuss parametrization of key uncertainties in the reservoir rock, fluid properties, fracture geometry and the effective permeability of stimulated rock. Ensemble-based assisted history matching algorithms are utilized to reduce and characterize the uncertainties in the model parameters by honoring various types of data including field dynamic data and measurements. We discuss the implementation of automated schemes for weighting of various types of data in the ensemble-based history matching algorithms. These schemes are introduced to define the history matching objective functions from various types of data including bottomhole pressure data, and the oil, water and gas productions rates. The computational results show that our adaptive scheme obtains better history match solutions.
The presented multi-scenario approach, coupled with the ability to efficiently run a high number of scenarios, enables better understanding of reservoir and fracture properties and shortens the learning curve for new development in unconventional assets. The shown case study illustrates a comprehensive analysis, using thousands of simulation cases, to obtain multiple history match solutions. Given the non-uniqueness of reservoir history matched models presented in the scenarios, this workflow improves forecasting ability and enables robust business decision makings under uncertainty.
Potential of Associative Polymers as Mobility Control Agents in Low Permeability Carbonates
Authors: Ghosh Pinaki , Zepeda Angel , Bernal Gildardo , Mohanty Kishore 
Published: September 2019

Abstract
Waterflood in low permeability carbonate reservoirs (&lt;50 mD) leaves behind a substantial amount of oil due to capillary trapping and poor sweep. Addition of polymer to the injected water increases the viscosity of the aqueous phase and decreases the mobility ratio, thus, improving the sweep efficiency and oil production from the tight formations. Performance of current synthetic EOR polymers is limited by salinity, temperature and injectivity issues in low permeability formations. Mechanical shear degradation can be applied to high molecular weight synthetic polymers to improve the injectivitiy; but makes the process less economical due to significant viscosity loss and consequent increase in polymer dosage. Recently, a different class of polymer has been developed called "hydrophobically modified associative polymers (AP)". The primary goal of this work is to investigate the performance of associative polymers in low permeability carbonate reservoirs. We compare the performance of associative polymers with that of conventional HPAM polymers in low permeability formations. A low molecular weight associative polymer was investigated as part of this study. A detailed study of polymer rheology and the effect of salinity at the reservoir temperature (60 °C) was performed. Additional experiments were performed in bulk and porous media to investigate the synergy of associative polymers with hydrophilic surfactant blends at different brine salinities. Single phase polymer flow experiments were performed in outcrop Edwards Yellow and Indiana limestone cores of low permeability to determine the optimum polymer concentration to achieve the desired in-situ resistance factor (or apparent viscosity). Similar experiments were performed with HPAM polymer for a comparative study. Results showed successful transport of this associative polymer in low permeability formations after a small degree of shear degradation. The resistance factors for the associative polymer were higher than those for HPAM. Shear degraded polymers showed significant improvement in polymer transport in lower permeability cores with reduction in RRF.
Casing Connection Break Detection Through Tubing in Canadian Thermal Projects. Case Study.
Authors: Ghanavati Mohsen , Volkov Maxim , Nagimov Vener , Ali Mohammadi Hamzeh 
Published: September 2019

Abstract
Production casings of Cyclic Steam Stimulation (CCS) or steam-assisted gravity drainage wells are exposed to significant temperature variations which in many cases resulted in casing breaks in the weakest part which are typically connection joints. The paper focuses on the new downhole logging approach, in monitoring and detecting production casing connection breaks through tubing without requirement for tubing retrieval.
The metal well barriers can be assessed by utilizing electromagnetic (EM) pulse defectoscopy. This is done by running multiple coaxial sensors downhole in tandem. Each sensor generates EM pulse and then records EM decay from surrounding metal tubes. Modeling of recorded EM decay enables precise assessment of metal loss or metal gain in up to four concentric barriers. However, the tool had never been used previously to detect minor defect features as casing breaks through the tubing. To identify casing breaks several yard and field tests have been conducted and new methodologies were developed. The last one included the recognition of specific patterns of raw EM responses, analysis of hole sensors and utilization of data from all coaxial sensors utilized during the downhole survey.
The new approach including downhole EM pulse tools and new data analysis have been implemented to detect casing connection breaks in over a hundred Cyclic Steam Stimulation (CCS) and SteamAssisted Gravity Drainage (SAGD) wells. The paper demonstrates the testing of the application feasibility in a comprehensive yard test and extends to real field examples. All detected breaks were confirmed after tubing removal and were successfully repaired. Paper highlights detection challenges due to different casing connection break types: minor breaks, partial breaks (contrary to fully circumferential), and casing breaks aligned with tubing connections. The technology has helped Operators to fulfil the objectives of connection break detection without tubing removal through a non-intrusive, safe, quick and economical approach.
Today, CSS and SAGD Operators should confirm casing integrity repeatedly prior to each subsequent steam cycle through the time and resource consuming approach of tubing removal and checking the casing integrity mechanically. Utilizing through tubing electromagnetic diagnostics, enables Operators to pick up multiple casing connection breaks in a single run without tubing retrieval.
Scaling Criteria for Hybrid Steam-Solvent Processes
Authors: Lorimer Shelley , Meza Diaz Brigida , Sawatzky Ron , Huang Xiaolan 
Published: September 2019

Abstract
Scaling groups for hybrid steam-solvent recovery processes are presented in this paper. A brief discussion of the derivation of the scaling groups is given first. Then an examination of the comparative behavior of these scaling groups at different scales is provided using reservoir simulation for the example of a high solvent load steam-butane gravity drainage process (i.e., steam-butane hybrid (SBH)).
Scaling groups were derived for hybrid steam-solvent recovery processes by inspectional analysis using governing equations for multi-phase flow in porous media. The effects of key mechanisms in these processes (diffusion, dispersion, advection and capillary pressure) were examined within the context of the derived scaling groups using reservoir simulation of SBH at three different geometric scales, ranging from the laboratory scale through a semi-field scale to the field scale, for one specific set of operating conditions. The scaling groups were used to analyse and interpret the numerical results.
The scaling groups were characterized according to the physical mechanisms from which they were derived. The intent of this analysis was to determine which of the mechanisms tend to be most important to the SBH process at different geometric scales. It is clear from a cursory examination of the scaling groups that all of the scaling groups representing the behavior of the SBH process cannot be satisfied when the geometric scale is changed from the laboratory scale to the field scale. The results of the study also indicate that the Pujol and Boberg scaling criteria for thermal processes seem to provide a reasonable approach for scaling SBH, when they are adapted to include the effects of dispersion. The influence of capillary pressure was secondary to other mechanisms involved in the process. It was evident from the simulations that the influence of dispersion was much more pronounced than diffusion for the solvent loading that was considered. Further, it was found that mechanical dispersity must be scaled with length to scale this mechanism appropriately in the reservoir simulator that was used in this study (CMG STARS™). As a final observation, the influence of capillary pressure was secondary to other mechanisms involved in the process.
Few studies on scaling high solvent loading hybrid steam-solvent processes have been undertaken. Using reservoir simulation to study scaling groups for these processes is a novel approach to this subject. Understanding the scalability of hybrid steam-solvent processes from the laboratory scale to the field scale would improve the capability of laboratory experiments to represent the performance of these recovery processes at the field scale.
Changing the Negative Perception of the Oil and Gas Industry In Colombia, Through an Energy Education Methodology
Authors: Guevara Israel , Pastor Paola , Saavedra Ana 
Published: September 2019

Abstract
In Colombia, oil and gas production contributes to a 4.4% of GDP as of 2016 and is considered a vital resource for the national economic development. Today, the oil and gas production is around 830.000 barrels per day. In the past 100 years, there are key geographical areas in the country where the oil and gas industry has been operating. Over the years, the oil and gas industry in Colombia has faced challenges with the communities behavior, environmental incidents and changes on the environment regulation. As a result of this, in the last three years Colombia has reported more than 9,000 barrels of oil per day (bpd) of deferred production, due to strikes that directly affect field operations.
The following article describes the factors considered in Colombia for the successful adaptation and application of Energy4me, a Society of Petroleum Engineers energy education methodology that explains the oil and gas concepts through innovative laboratories that help understand, in a simple way, how the oil industry works.
In the last two years, more than 8,000 people have been involved in the Energy4me program in Colombia. This paper describes the methodology applied for the successful execution of the Energy4me program; integrating the analysis of the targeted population, adaptation of the technical information and the industry's view on the environment. Additionally, it quantitatively portraits the participation of student volunteers from different universities around the country and the positive impact of this experience. Sample design techniques and data analysis are applied to quantitatively measure the results obtained, among which stands out the decrease of the energy industry rejection by at least 58%, as well as other benefits; which are backed up by the theory of shared value.
With the novel adaptation and implementation of the pedagogical methodology of Energy4Me and with the creation of new educational materials to simplify technical knowledge sharing, it is concluded that a healthy communication channel between the energy sector and the communities exposed to oil operations can be constructed to achieve a reduction in the overall communities oil and gas rejection.
SAGD Production Optimization Through Preferential Steam Allocation
Authors: Aboorvanathan Raphael , Hossini Amir , Dong Chao , Dehdari Vahid , Feeney Jay 
Published: September 2019

Abstract
Optimizing steam-assisted gravity drainage (SAGD) performance in oil sands reservoirs relies on the quality of steam allocation decisions made across the well inventory. With finite facility steam generation capacity, SAGD producers are typically challenged with identifying the true opportunity cost of allocating steam volumes based on well performance. This paper presents a novel technique to inform steam allocation decisions and managing SAGD reservoir pressures in service of optimizing production and consequently improving the economic performance of the asset through smarter SAGD field development planning.
The concept of marginal steam-oil-ratio (mSOR) is introduced as a method of guiding steam allocation decisions. Marginal SOR is defined as the cold-water equivalent volume of steam required to produce the next marginal barrel of bitumen from the production system in a steam constrained environment. The metric represents the opportunity cost of deploying a barrel of steam to the next best alternative in steam allocation decisions. Dynamic quantification of mSOR over the plausible range of operating pressures for each producing entity (PRDE) in the inventory (such as a well group or drainage area) is critical to optimally allocating steam when faced with reservoir challenges such as reservoir complexity and heterogeneity and transient reservoir behaviors such as thief zone interaction.
This paper prescribes methodologies to analytically and empirically quantify mSOR for a SAGD production system. Additionally, application of the concept if field production optimization is discussed under the context of integrated production modeling and constrained flow network optimization problems. A case example of applying mSOR to guide steam allocation decisions at ConocoPhillips' Surmont SAGD asset is presented under a steam constrained environment. The mSOR guided solution is validated using brute-force enumeration of steam allocation outcomes in the production system to prove production optimality. The results from this dynamic steam allocation strategy guided by mSOR characterization show significant improvements in field oil rates, field steam management efficiency and consequently the economic value of the SAGD asset.
Shifting the Perspective: Modernizing Well Density Metrics for Multi-Layer Horizontal Well Development
Authors: Hansen Mary , Hamm Brian , Wynveen Jared , Schlosser Tyler , Jenkinson David , Dang Hoang 
Published: September 2019

Abstract
Unconventional reservoirs with low permeability shales and siltstones are currently being developed using horizontal wells in multiple layers. As this development technique has become more common, accurately understanding well-to-well communication is increasingly critical. Well positioning, reservoir thickness and well interference effects are important factors in the success of multi-layer development. Traditional well density metrics such as wells per section and lateral well spacing do not account for the multi-layer nature of these plays. This paper introduces readily derived metrics that enable a three-dimensional (3D) quantification of multi-layer well density.
Unlike traditional analysis which considers pad development from a bird’s eye view, this paper considers the vertical cross-section of a pad which enables the 3D drainage to be quantified. The metrics Cross-Sectional Drainage Area (XDA) and Three-Dimensional Proppant Intensity (3DPI) are defined. XDA quantifies the well density relative to the thickness of the reservoir. 3DPI represents completion intensity and reservoir stimulation relative to the cubic volume of gross rock attributed to the multi-layer development. Once introduced, these two metrics are correlated to well and pad level performance. Examples from the Montney Formation in Western Canada and the Bakken Formation in North Dakota, USA are studied in detail.
Ultimate hydrocarbon recovery factors, early time well performance and production profiles are analyzed and compared to the XDA and 3DPI metrics using visual analytics and multivariate machine learning models. In both the Montney and Bakken examples, XDA correlates with well performance and 3DPI correlates with pad hydrocarbon recovery factors.
Determination of ISIP of Non-Ideal Behavior During Diagnostic Fracture Injection Tests
Authors: Ibrahim Mohamed Mohamed , Ibrahim Ahmed Farid , Ibrahim Mazher , Pieprzica Chester , Ozkan Erdal 
Published: September 2019

Abstract
The instantaneous shut-in pressure (ISIP) serves as an indication of the excess pressure in the hydraulic fracture due to the effect of fluid viscosity and pressure required to break the formation at the fracture tip. The ISIP value will be close to or at the fracture propagation pressure and will be greater than the fracture pressure. The ISIP is often estimated to be the pressure after the pumps are shut down, and the beginning of a pressure decline. Many approaches have been developed to estimate the ISIP from the falloff data. The development of these approaches is attributed to the persistent trials due to the difficulty of quantifying the ISIP value accurately. Giving bottomhole pressures, ISIP can be estimated by subtracting the friction pressure drop from bottomhole pressure. This approach tends to overestimate the value of ISIP as it doesn't account for friction near the wellbore or through the perforations. Another common approach to estimate ISIP is by drawing a straight line on the early falloff portion of the Diagnostic Fracture Injection Tests (DFIT).
Previous studies show that the choice of ISIP affects the net pressure calculations, but not the slope of the derivative curves and the flow regime identification. This paper presents field cases where the values of ISIP affects the interpretation of the reservoir characteristics. Thus, the determination of accurate ISIP is very crucial.
This paper reviews the previously proposed approaches for determining the ISIP and provide a state of the art simple method to determine ISIP from non-ideal falloff data. The ISIP determined from the proposed method is verified by examination of the semi-log derivative plot, and the interpreted reservoir characteristics were found to be consistent with both field and lab observations. The method was validated using field DFITs falloff data from high-pressure dependent leakoff formations as well as formations that yield normal leakoff pressure dependent.
The novelty of the proposed method is in the simplicity of determination of ISIP and the consistency with the field observations. A number of field examples from the Barnett shale are illustrated using mechanisms previously proposed in the literature as well as the method presented in this paper. The later provided consistent ISIP values after multiple iterations. Subsequently, the reservoir characteristics and calculated parameters were uniform within the same pad of wells.