bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modular Functions of Electronic Frac Sleeve
Authors: Walton Zachary , Fripp Michael , Merron Matt 
Published: September 2019

Abstract
A new electronic sliding sleeve has been developed for hydraulic fracturing that combines the best features of traditional sliding sleeves and plug and perf techniques. This battery-powered electronic sliding sleeve provides the operational efficiency of sliding sleeves in an unlimited number of zones. The firmware, electrohydraulic lock, and electronics package in this new sliding sleeve help enable a range of operational functions for use in hydraulic fracturing.
Traditional sliding sleeves use a series of progressively sized balls that shift sleeves by landing on progressively sized baffles. An electronic sliding sleeve creates a monobore construction with the same inside diameter bore in each sleeve and helps enable treating of an unlimited number of zones. The electronics in the sliding sleeve helps eliminate the mechanical complexity of other monobore fracturing tools. The firmware and electronic package enable a modular approach to electronic sleeve design. Therefore, one frac sleeve chassis design can be used for many of the different types of sleeve tools in the well completion, and the firmware that drives the electronics is modified for each respective type of tool.
Using combinations of the electrohydraulic lock, electronics package, and firmware can enable the design of all the tools necessary to complete a wellbore. The standard firmware, used for a single point entry sleeve, operates by counting the correct number of frac balls. When the correct count is reached, the electrohydraulic lock is released, enabling sleeve movement or zonal isolation deployment. A modification can be made to the firmware to have the tool actuate on the next count, rather than the initial count, and delay the time at which the electrohydraulic lock is released. This type of architecture lends itself to the design of multi-entry sleeves. The sensor can also be eliminated by using the delay feature in the firmware of the electrohydraulic lock, programmed in weeks. This type of architecture also helps enable the design of a toe sleeve.
Having the ability to implement slight modifications to the components that make up the sliding sleeve enables design flexibility and modularity for all sleeve type tools necessary to complete a wellbore. This type of system architecture helps decrease operator risk and ease design constraints while performing multiple functions downhole.
Sub-Surface Driven Connectivity Descriptions in the Montney and the Duvernay Inform the Applicability of Single-Point Versus Multi-Point Well Architectures
Authors: Stephenson Ben , Bai Taixu , Fay Mathew , Galan Earl , MacDonald Jeff , Carduner Ryan 
Published: September 2019

Abstract
A single-point entry completion architecture has been implemented in several hydraulically stimulated resource plays across North America. The objective is to understand whether the innate properties of the rock and what we can diagnose about how it hydraulically fractures can inform the question of applicability of single-versus multi-point completion designs.
Wells were treated using a single-point entry design in the Montney and the Duvernay and an assessment of well performance was carried out. Multiple diagnostic pads have been carried out over several years in both formations, including microseismic and geochemical fingerprint data allowing for a general characterization of the gross geometry and connectivity. Initial results from a fiber are available in the Montney with a single point completion design. The fracture diagnostic data was compiled and described in the context of the nine main sub-surface controls on the connectivity.
In the Montney, it is relatively clear how completion intensity changes, like stage length, in single-point entry wells change the production performance outcome. In the Duvernay, there is significantly more uncertainty. This contrast contributed to the decision to treat several follow-up pads in the Montney via a single-point entry design, whereas a multi-point plug and perf completion is preferred for the Duvernay wells. Costs and stage isolation are considerations, but one other contributing explanation is that the dominantly planar fracture geometry in the Montney enables each stage to contribute proportionally, thus ensuring the stimulation distribution effectiveness from the near-to the far-field.
The dry-gas area of the Montney is very stiff, with an absence of natural fractures, a paucity of faults, no containment issues and no significant frac barriers. Conversely, in the Duvernay, the inherent complexity in the fracture geometry complicates the stimulation distribution effectiveness in the far-field. Furthermore, the lower mobility of a liquids-rich hydrocarbon system probably benefits from the potentially tighter frac spacing, possible in a multi-cluster design, even with a probable increase in non-uniformity over single-point.
It is hypothesized that in formations that develop complex fracture geometries, ‘putting all your eggs in one basket’ with a single-point entry design, needs to be assessed along with the other value drivers for the well architecture selection.
A Game Changer Data Acquisition Technology : Field Wide Gaslift Optimization through the Application of Welltracer Technology in a Mature Offshore Field
Authors: Mohd Khalil Muhammad Idraki , Chang Claire Li , Amran Amierul , Kok Jason Chin 
Published: September 2019

Abstract
90% of Field T production relies on Gas lift as means of artificial lift. Typical surveillance strategy in assessing the health of the gas lifted wells is to deploy flowing gradient survey (FGS) in tandem with surface welltest. However, in the case of Field T, this technology meets its limitation in investigating prolific wells due to its current well mechanical condition and dual string completion environment. Welltracer technology application in the field has broken the barrier in evaluation of these wells in Field T.
The Welltracer application is a non-invasive data acquisition method which measures the travel time and concentration of the CO2 return which is introduced upstream of the gas lift header. The interpreted results allow for the identification of injection points and rate. This simple idea opens up opportunity for gas lift performance evaluation of wells in Field T that was not possible through the conventional approach of FGS. This breakthrough is vital for Field T as some of the wells are facing either one or more of the following problems i.e. dual string wells with gas robbing issues, tubing leak, restricted tubing due to pack-off and multi-point injection.
Twenty-three surveys and analysis were completed during the first application in Field T. The opportunity identified from the survey were categorized depending on the resources and timeframe required to execute the changes. Four enhancement opportunities were identified which only required surface valve manipulation were executed immediately and showed instant results. Other than additional barrels, the results of the campaign have a tremendous value of information that changed the earlier comprehension of the existing problems in some of the wells.
This paper discusses the results of the application of the technology in Field T. This paper will also elaborate on the lessons learned and improvement recommendations in terms of project identification, execution and planning. Another important highlight that will be discussed is the limitation and assumptions made to further enhance the understanding of the Welltracer technology.
Performance Analysis of the Artificial Lift Systems for Heavy Oil Wells in the Egyptian Eastern Desert
Authors: El Gharbawi Mahmoud Atef , Elgibaly Ahmed Ahemd , Salem Adel Mohamed , Abbas Mohamed 
Published: September 2019

Abstract
This paper describes the implementation of a performance analysis (PA) review and a comprehensive root cause failure analysis (RCFA) for the artificial lift system (ALS) failures in heavy oil wells. The subject wells, located in Egyptian Eastern Desert (EED), have been operated by Canadian-Egyptian joint venture. Progressive cavity pump (PCP) and beam pump (BP) have been selected as the preferred ALS methods. With the objective of improving ALS performance, RCFA identifies the main causes of ALS failures and proposes guidelines and recommendations with a new open source service for the current and future development for EED Oil companies.
PA has been applied using some Key Performance Indicators (KPI), such as: failure index, recurrence index, and average run life in order to track all failed and crucial issues. RCFA has been applied to different ALS, such as: BP and PCP. Therefore, the definition or limitation of the boundaries of each system and the classification of failures were performed. RCFA covered failures between 2012 and 2018 for average 150 active wells and 622 failures. Finally, the new open source service applied as a trial to evolve the failure tracking and decision making methodology.
PA review showed a high failure and recurrence index that reached 3.0 and 3.7, respectively, in 2014 then declined to 1.0 and 1.7, respectively, in 2017 as a result of comprehensive corrective actions implemented. RCFA showed that rod string failure in BP was and still is a dominant failure with 200 failures over the last six years. Moreover, Down-hole pump failure in PCP was the major PCP failure system although its failures declined from 80 failures in 2014 to 14 failures in 2018. Several field cases were presented to cover the dominant cause of failures for both BP and PCP wells. Most wells had a significant improvement in their mean time to failure (MTTF) after reviewing design, installation and operation procedures.
The procedure for carrying out this methodology and implementing lessons learned has been presented in this paper. In addition, the new open source integration service provides an increased visibility about individual well performance issues and more broadly, about field performance and ALS failures.
Evaluating Precision of Fluid/Casing Design for Annular Pressure Build-Up APB Application Using Machine-Learning Tools
Authors: Kulkarni Sandeep D. , Vyas Aditya , Gupta Himanshu 
Published: September 2019

Abstract
Annular Pressure Build-up (APB) is caused by heating of the trapped drilling fluids (during production) which may lead to burst/collapse of the casing or axial ballooning, especially in subsea HP/HT wells. The objective of present paper is to apply machine-learning tools to increase precision of the APB estimation, and thereby improve the fluid and casing design for APB mitigation in a given well.
The APB estimation methods in literature involve theoretical and computational tools that accommodate two separate effects: volumetric expansion (PVT response) of the annulus drilling fluids and circumferential expansion (and corresponding mechanical equilibrium) of the well casings. In the present work, machine-learning algorithms were used to accurately model ‘fluid density=f(T,P)’ based on the experimental PVT data of a given fluid at a range of (T, P) conditions. Sensitivity analysis was carried out to demonstrate improvement in precision of APB estimation (for different subsea well scenarios employing different fluids) using the machine-learning based models.
The study demonstrated that, in several subsea scenarios, a relatively small error in the experimental fluid PVT data itself can lead to significant variation of in APB estimation. The machine-learning based models for ‘density = f(T,P)’ for the fluids ensure that the cumulative error during the modeling process is minimized. The use of certain machine-learning based density models was shown to improve the precision of APB estimation by several hundreds of psi. This advantage of the machine-learning based density models was employed to improve the casing/fluid design for APB mitigation; the case was demonstrated for a subsea well scenario. Accordingly, the work may be used to mitigate the APB issue in the subsea HP/HT wells.
Field Case Studies of Downhole Electric Heating in Two Horizontal Alberta Heavy Oil Wells
Authors: Penny Scott , Karanikas John M , Barnett Jonathan , Harley Guy , Hartwell Chase , Waddell Trent 
Published: September 2019

Abstract
Downhole electric heating has historically been unreliable or limited to short, often vertical, well sections. Technology improvements over the past several years now allow for reliable, long length, relatively high powered, downhole electric heating suitable for extended-reach horizontal wells. The application of this downhole electric heating technology in two different horizontal cold-producing heavy oil wells in Alberta is presented.
The first field case study discusses the application of electric heating in a mature, depleted field as a secondary recovery method while the second case study examines a virgin heavy oil reservoir, where cold production by artificial lift was economically challenged. The completion, installation, expected and actual results of both cases studies are compared and contrasted.
Both field deployments demonstrate the benefits and efficacy of applying downhole electric heating. In the case of the mature depleted field, electric heating resulted in a 4X-5X increase in oil rate, sustained over a period of close to two years. The energy ratio of the heating value of the incremental produced oil to the injected heat was slightly over 7.0. In the virgin heavy oil field, electric heating reduced the viscosity of the oil in the wellbore from time zero, which allows for higher rates of oil production along the complete length of the long horizontal lateral at higher, if desired, bottomhole pressures than in a cold-producing well. This degree of freedom may ultimately allow for an operating policy that suppresses excessive production of dissolved gas, thereby helping conserve reservoir energy. Early production data in this field show 4X-6X higher oil rates form the heated well than from the cold-producing benchmark well in the same reservoir.
Numerical simulation models, which include reactions that account for the foamy nature of the produced oil and the downhole injection of heat, have been developed and calibrated against field data. The models can be used to prescribe the range of optimal reservoir and fluid properties to select the most promising targets (fields, wells) for downhole electric heating as a production optimization method, which is crucially important in the current low oil price scenario. The same models can also be used during the execution of the project to explore optimal operating conditions and operating procedures.
Downhole electric heating in long horizontal wells is now a commercially available technology that can be reliably applied as a production optimization recovery scheme in heavy oil reservoirs. Understanding the optimum reservoir conditions where the application of downhole electric heating maximizes economic benefits will assist in identifying areas of opportunity to meaningfully increase reserves and production in heavy oil reservoirs in Alberta as well as around the world.
An Efficient, Robust, and Data-Oriented Inversion Method for Noisy T2 Echo Trains
Authors: Li Baoyan , Arro Roberto , Thern Holger , Kesserwan Hasan , Jin Guodong 
Published: September 2019

Abstract
For NMR logging of hydrocarbon bearing formations, the inversion of T2 echo trains is a critical pre-processing step to compute porosity, permeability, and fluid saturations of formations. To accurately and efficiently invert NMR measurement data, a new inversion method is presented to compute the optimal solution of T2 distribution with a unique optimal regularization factor for NMR logging data processing. This inversion method has no assumption about the white noise of a T2 echo train.
A new supplementary nonlinear equality constraint was introduced to optimize the solution of T2 distribution by explicitly taking into account the measured noise of a measured T2 echo train. An efficient iterative algorithm has been developed to solve the nonlinear optimization problem defined in the new inversion method. An initial-guess solution of the regularization factor was proposed for accelerating the searching process of the regularization factor.
The new inversion method has been verified with synthetic T2 echo train data and applied to process T2 echo train data of core samples of carbonate and Berea sandstone formations that are saturated with different fluids. This method has also been compared with conventional methods. The testing and comparison results show that: The optimal solution of T2 distribution from the new inversion method has a unique solution that is independent of the pre-selected values of regularization factor, so does the regularization factor. The optimal solutions T2 distribution and regularization factor will be convergent to their true solutions when the SNR of echo train data becomes sufficiently high.The computation cost for searching the optimal solutions of T2 distribution and regularization factor using the new nonlinear optimization algorithm is only a few iterations.The initial-guess solution of the regularization factor is more close to the solution determined from the S-curve method, which could be higher than the optimal solution of the regularization factor searched in the new inversion method.
Chemical Flood of a Viscous Oil with Novel Surfactants
Authors: Panthi Krishna , Weerasooriya Upali , Mohanty Kishore 
Published: September 2019

Abstract
The goal of this work is to evaluate the applicability of a novel set of surfactants to enhance recovery from a viscous oil, high temperature, high permeability, clastic reservoir. A large number of novel short-hydrophobe based surfactants/cosolvents were designed and synthesized. As these surfactants do not require expensive aliphatic alcohols for their synthesis, they are likely to be less costly than conventional anionic surfactants. Here only phenol hydrophobe based non-ionic surfactants with varying number of propylene oxide (PO) and ethylene oxide (EO) groups are discussed. These surfactant molecules were investigated for their aqueous stability limits, interfacial tensions (IFT) with a viscous crude oil and oil recovery from sandpack or sandstone cores. Surfactant phase behavior experiments with viscous crude oil showed low IFT (not ultralow) for single surfactant systems. Only one surfactant (Phenol-7PO-15EO) formulation was chosen for coreflood in sandpack and sandstone cores. Water flood recovered about 50% original oil in place (OOIP) and reduced the oil saturation to about 48% in the high permeability sandpacks. The tertiary surfactant polymer flood with Phenol-7PO-15EO increased the cumulative recovery to 99% for sandpacks. The oil recovery was insensitive to injection brine salinity in the range studied. As the permeability decreased, the tertiary oil recovery decreased if the permeability is lower than 7 Darcy. Surfactant-polymer (SP) formulations with this surfactant can be recommended for high permeability sandstone reservoirs with viscous oils, but not for sub-Darcy sandstones.
CT Coreflood Study of Transient Foam Flow with Oil
Authors: Tang Jinyu , Vincent-Bonnieu Sebastien , Rossen William R. 
Published: September 2019

Abstract
We present a CT coreflood study of foam flow with two representative oils: hexadecane C16 (benign to foam) and a mixture of 80 wt% C16 and 20 wt% oleic acid (OA) (very harmful to foam). The purpose is to understand the transient dynamics of foam, both generated in-situ and pre-generated, as a function of oil saturation and type. Foam dynamics with oil (generation and propagation) are quantified through sectional pressure-drop measurements. Dual-energy CT imaging monitors phase saturation distributions during the corefloods. With C16, injection with and without pre-generation of foam exhibits similar transient behavior: strong foam moves quickly from upstream to downstream and creates an oil bank. In contrast, with 20 wt% OA, pre-generation of foam gives very different results from co-injection, suggesting that harmful oils affect foam generation and propagation differently. Without pre-generation, initial strong-foam generation is very difficult even at residual oil saturation about 0.1; the generation finally starts from the outlet (a likely result of the capillary-end effect). This strong-foam state propagates backwards against flow and very slowly. The cause of backward propagation is unclear yet. However, pre-generated foam shows two stages of propagation, both from the inlet to outlet. First, weak foam displaces most of the oil, followed by a propagation of stronger foam at lower oil saturation. Implicit-texture foam models for enhanced oil recovery cannot distinguish the different results between the two types of foam injection with very harmful oils. This is because these models do not distinguish between pre-generation and co-injection of gas and surfactant solution.
Frac Plug Pump Down Efficiencies and Techniques
Authors: Walton Zachary , Nichols Matthew , Fripp Michael 
Published: September 2019

Abstract
Plugs for hydraulic fracturing generally are pumped into horizontal wellbores. Initially, the goal was to get the plugs to depth without careful consideration of the amount of water used in the pumping. As the industry has grown, a better understanding of pump-down methods and techniques has resulted in a realization that these pumping inefficiencies should be improved.
When completing a horizontal well using the plug-and-perf technique, water is required to push the bottom hole assembly (BHA), containing a frac plug, to the target depth. With over one million frac plugs having been pumped in North America, large data sets are available to quantify the pump-down efficiency of these operations. This past information, along with a working model of how pump down works, can be used to promote improvements in pump-down efficiency, reducing water usage and rig time.
The efficiency of the pump-down operation can be calculated based on pump time, displacement volume, and the actual volume of fluid pumped. This type of information can be recorded during operations. The pump-down efficiencies can be calculated as a percentage of actual versus calculated volumes pumped and is often expressed as a relational number, such as how much fluid is needed per 100 feet of casing. These numbers can be used as a metric for the amount of water and time required to move the plug to its desired location.
Over 10,000 frac plug pump downs from diverse North American regions were analyzed to attain a baseline for efficiency during frac plug pump down operations. The force, pressure, and fluid velocity effects acting on the BHA during pump down were analyzed to understand how to better quantify methods and designs that increase or decrease efficiency. Finally, procedures were mapped out on the operational units used in pump down to understand the potential impacts on efficiency.
The result is a guide on gauging pump-down efficiency of past operations while understanding methods to increase these efficiencies in the future. This framework can be used to view how a frac plug is pumped downhole while understanding the relationships that control its efficiency. This model can be used to evaluate past operations as well as design for future operations to increase overall efficiencies and decrease water usage and time on location.