bluuebunny/crossref_metadata_2025_split huggingface dataset:
Measurement of Reduced Permeability at Fracture Face Due to Proppant Embedment and Depletion
Authors: Karazincir Oya , Li Yan , Zaki Karim , Williams Wade , Tan Yunhui , Wu Ruiting , Rijken Peggy , Rickards Allan 
Published: October 2018

Abstract
Proppant embedment at the fracture face of a hydraulically fractured formation can result in reduced hydrocarbon flow from the matrix into the fracture due to reduced pore throat size, crushing of the rock, fines generation and pore plugging within the embedment zone (i.e. at the fracture face). Conventional proppant conductivity tests can only measure conductivity losses that occur within the proppant pack due to frac gel damage and compaction, not the damage at the fracture face. Test methods that can directly measure the effect of embedment on hydrocarbon production rates from a fracture are needed. A new test method that can measure proppant embedment at the fracture face as a function of different variables such as depletion, formation UCS and permeability, proppant type and loading has been developed. The same test method can also measure the resulting changes in the fracture-face permeability and the rate of fluid flow from the matrix into the fracture as a function of depletion, coupled with conductivity measurement within the proppant pack. A numerical model was built to provide reference solutions for the initial permeability.
Aquifer Monitoring Technology for Safe Shale Oil and Gas Exploration and Extraction
Authors: Tuxen Anders , Boughrara Salman Amina , Davis John , L. Pedersen Poul , L. Byg Casper , Frederiksen Maj , A. Hansen Jacob , N. Skov Søren , T. Kjeldsen Kasper , Hone Jim , Wood Andrew , T. Craster Bernadette , Shillam Jason 
Published: October 2018

Abstract
Analysis of dissolved methane and volatile organic compounds (VOCs) in water is crucial in monitoring the underground water quality, specific to shale oil and gas subsurface activities. Existing methods for monitoring these analytes generally rely on manual sampling at hydrogeological boreholes followed by off-line chromatography-based laboratory analysis. These methods are labor intensive and prone to errors. In addition, they do not capture the dynamic variations, which are particularly interesting in the occurrence of methane. In this work, a new sensor-based instrumentation for in-situ detection and measurement of methane and VOCs in subsurface environments is presented. The methane detection method relies on the Non-Dispersive Infrared technology whereas VOCs are detected using the principle of photoionization detection.
It is demonstrated that the system has a relatively short response time combined with low detection limits for methane and VOCs. This makes the system suitable for monitoring aquifers in shale gas exploration sites with a fairly high temporal resolution thus giving information on dynamic variations in the methane and VOC concentrations.
Integration of Dual-Porosity Modeling with 4D Seismic and Microseismic Technology in Niobrara and Codell Formations, DJ Basin
Authors: Ning Yanrui , Kazemi Hossein , Davis Tom 
Published: October 2018

Abstract
This paper presents construction and validation of a reservoir model for the Niobrara and Codell Formations in Wattenberg Field of the Denver-Julesburg Basin. Characterization of Niobrara-Codell system is challenging because of the geologic complexity resulting from the presence of numerous faults. Because of extensive reservoir stimulation via multi-stage hydraulic fracturing, a dual-porosity model was adopted to represent the various reservoir complexities using data from geology, geophysics, petrophysics, well completion and production. After successful history matching two-and-half years of reservoir performance, the localized presence of high intensity macrofractures and resulting evolution of gas saturation was correlated with the time-lapse seismic and microseismic interpretations. The agreement between the evolved free gas saturation in the fracture system and the seismic anomalies and microseismic events pointed to the viability of the dual-porosity modeling as a tool for forecasting and future reservoir development, such as re-stimulation, infill drilling, and enhanced oil recovery strategies.
Application of Conventional Forecasting Methods to Waterfloods with Horizontal Wells in Heavy Oil Reservoirs
Authors: Delamaide Eric 
Published: October 2018

Abstract
Using horizontal wells for primary production of heavy oil reservoirs is common in Canada but it is less frequent to employ them for waterflood. As a result, very few papers have been published on this topic. Similarly, numerous publications are available on the use of conventional forecasting methods to evaluate waterflood performances, but very few if any have focused on waterfloods with horizontal wells in heavy oil reservoirs. This is what this paper proposes to do.
The production performances of over twenty horizontal wells from five Canadian heavy oil pools where waterflood has been implemented using horizontal wells have been studied. The pools are thin and bottom water is present in some of them; oil viscosity ranges from a few hundred to a few thousand centipoises. Conventional waterflood forecasting methods such as Arps, Yang and logarithm of Water-Oil Ratio (WOR) vs. Cumulative oil production were used and compared. However, the focus of the paper is not only the comparison of the various forecasting methods but also the evaluation of the performances of horizontal well waterfloods in these high oil viscosities.
The Arps method appears difficult to use, especially when there are strong variations in injection rates. By comparison, the Yang and the WOR vs. Cumulative production methods appear more stable. The forecast in cumulative production can vary widely between these methods. Ultimate recovery is expected to vary from a few percent OOIP to over 20%OOIP.
This paper will present the performances of several horizontal waterfloods in heavy oil reservoirs in Canada and compare several waterflood analysis methods. Very few if any paper has been published on this topic thus the information provided will be of interest to engineers who are considering using horizontal wells for waterflood as a follow-up to primary production in heavy oil reservoirs.
Managing Process Safety Risk at the Dynamic Frontline
Authors: Jones Simon , Brewer Courtney 
Published: October 2018

Abstract
Process safety approaches developed and implemented over the past 20-30 years have enabled us to improve the design basis of our facilities. Yet we still see major incidents occurring at a steady rate. Traditional approaches to risk management may be appropriate as a basis for design, but they are not helpful in operations management where decisions continuously take place that impacts exposure to Major Accident Hazard (MAH) risk.
A 2017 international survey1 looked into the state of process safety and risk management in the hazardous industries. 70% of survey respondents reported a gap between how process safety management is intended and the reality of operations. Only six percent of respondents indicated their companies were up-to-date on safety critical maintenance. The survey results highlighted that the real world of operations is neither simple nor static and highlighted a gap in organizations’ abilities to develop a single, shared view of the operational reality of risk.
The current trend towards digitalization of the industry offers companies an opportunity for a clearer understanding of risk to reduce incidents and enhance the journey towards sustainable production and Operational Excellence. So-called "big data" and "edge data" techniques applied to the streams of data arising from modern facilities holds out the promise of a process safety early warning system that looks at potential signals and trends in facility operations data to make MAH risk exposure visible, prominent and available in real-time.
A new category of Operational Risk Management (ORM) software tools is emerging which seek to deliver on this promise. This paper shares the approaches adopted by two major international oil industry operators who are leveraging a new approach to process safety and operational risk management to achieve safer, more sustainable operations.
A Novel Re-Crosslinkable Preformed Particle Gel for Conformance Control in Extreme Heterogeneous Reservoirs
Authors: Pu Jingyang , Bai Baojun , Alhuraishawy Ali , Schuman Thomas , Chen Yashu , Sun Xindi 
Published: October 2018

Abstract
Preformed particle gels (PPG) have been successfully applied to control conformance for mature oilfields due to its advantages over conventional in-situ gels. However, field applications have demonstrated that current particle gels cannot efficiently plug opening fractures, fractures-like channels, or conduits which exist in many mature oilfields. The objective of this study is to systematically evaluate a new re-crosslinkable preformed particle gel (RPPG) product which can be used to efficiently control the conformance for the abnormal features. The novel particle gels can re-crosslink to form a rubber-like bulky material in the large opening features after placement to significantly enhance the plugging efficiency. We systematically evaluated the effect of temperature, brine concentration and RPPG swelling ratio on the re-crosslinking time, the gel strength after crosslinking, and their thermos-stability. Core flooding tests were run to test whether RPPG can significantly improve the fracture plugging efficiency comparing to a traditional PPG which cannot re-crosslink after pumping. The RPPG can be customized for the mature reservoirs with the temperature from 23 to 80°C with controllable size from tens of nanometer to a few millimeters. The RPPG swelling ratio can be controlled from 5 to 40 times. Its re-crosslinking time can be controlled from 2 to 80 h, depending on absorbed water amount, brine concentration, and temperature. The gel elastic modulus after re-crosslinking can achieve from 300 to 10,800 Pa, depending on swelling ratio. Core flooding tests showed that the breakthrough pressure of the re-crosslinked RPPG can reach up to 300 psi/ft for the fracture with the width of 5 cm and 0.2 cm aperture, which is more than 5 times higher than traditional PPGs. In addition, the plugging efficiency of the RPPG is 20 times higher than 40 K.
The Impact of Fracture Effectiveness on the Economics of Haynesville Resource Development - A Case History
Authors: Shelley Robert , Davidson Brian , Shah Koras , Sheludko Stan , Mohammadnejad Amir 
Published: October 2018

Abstract
Evaluating the performance of relatively deep Haynesville completions indicate that well and project hydrocarbon recovery can be negatively impacted by ineffective hydraulic frac design. Understanding the potential causes of these effects opens the door to strategies which can deliver better fracture effectiveness with corresponding increases in production and improved project economics. The subject of this paper are results from a detailed evaluation of a Desoto Parish well. This evaluation included calibration of a frac model by treatment pressure matching, use of a numeric reservoir simulator for multi-phase production history matching and comparing the fracture characteristics estimated. Also changes in conditions within the fracture over time as the wells are produced are taken into account. These evaluations concluded that completion, frac design, operational and production issues - individually or collectively - meaningfully influence the production and economics of multi-stage horizontal completions. The bottom line: Well recovery can be improved considerably with more effective frac designs that generate and/or sustain a larger contributing fracture area.
The findings show that reservoir characteristics, completion, frac design and production practices are the primary drivers of Haynesville well production. In addition, the results indicate that the hydraulic fractures created are not very efficient, in other words large portions of the propped fracture area do not contribute to well performance. This inefficiency is primarily due to conductivity limitations which can be attributed to a variety of issues including frac design, loss of proppant permeability due to stress, pinch points in the proppant bed, capillary effects, fluid retention, embedment, etc. Inefficient fractures will require more wells to be drilled in closer proximity to achieve optimum primary production. In addition the closer well spacing required in combination with high proppant intensity and large treatment volumes will increase the likeliness of adverse child to parent well interaction.
Application of Superposition Principle to Variable Rate/Pressure Production Analysis in Unconventional Gas Reservoirs
Authors: Zhang Miao , Ayala Luis F. 
Published: October 2018

Abstract
Application of superposition principle to non-linear gas governing equations has been an elusive goal in early-transient production data analysis and has been so far limited to the use of empirical and approximate methods best applicable to boundary-dominated flow conditions. This paper presents a novel and rigorous semi-analytical model that is applicable for the analysis of production data from multi-fractured horizontal gas wells (MFHWs) producing under early-transient variable rate/pressure production conditions. Nonlinear, pressure-dependent hydraulic diffusivity retained in pseudo-pressure-based gas diffusivity equation is straightforwardly and rigorously captured without approximation. The resulting formulation of superposition applied in nonlinear gas system is written in terms of the classical solution for linear PDE plus an analytical adjustment factor that quantifies the nonlinearity of the system. Numerical examples are presented to test the validity and showcase the capabilities of proposed approach. Comparisons against available empirical and approximate models are also provided for these cases.
Challenges and Lessons Learned During Completion of Intelligent Multilateral Wells in Minagish Field, West Kuwait
Authors: Arackakudiyil Suresh Zac , Kumar Ajit , Rondon Leonque , Pingle Darshan , Al-Hindi Khaled , Boushahri Mohammed 
Published: October 2018

Abstract
Multilateral intelligent wells have been proven effective by both extending reservoir contact and providing proactive reservoir management. This paper highlights the lessons learned and critical well construction and completion steps that improve the efficiency of intelligent multilateral well drilling and completions operations. The case study outlines the successful completion of the third multilateral intelligent well in the Minagish field of West Kuwait.
The intelligent level 4 multilateral well was designed and drilled successfully. The sidetrack was performed using a specialized latch coupling that allowed for multilateral window cutting, orienting, and re-entry. The latch coupling was run in hole with the main bore casing, and a key orienting tool was used to confirm its orientation. Once the main bore was complete, a window was cut using a dedicated milling machine. Thereafter, a drilling whipstock was run with a window mill and watermelon mill to allow access to the lateral. This was followed by drilling the lateral section and running and cementing the liner. After the lateral section was drilled to the planned depth and cleaned out, the whipstock was retrieved. The intelligent completion installation consisted of a lubricator valve, two downhole permanent gauges, and two variable choke interval control valves.
The presence of surface-controlled, variable choke valves to control inflow from both the main bore and the lateral provides the capability to effectively manage the reservoir and production over the life of the well. This, in turn, prolongs the field life, thus improving overall economic performance and field economics. The case study well is the third multilateral intelligent well installed in Kuwait, and many recommended practices were implemented that allowed for improved efficiency and safety of the operation. Maintaining a clean well was emphasized as a top priority throughout the well construction process. The cement curing time was increased and the completion string was reviewed and redesigned.
This paper discusses the lessons learned and improvements made during installation of the third multilateral intelligent well. The steps performed during this operation have become the recommended practices for all upcoming intelligent multilateral well operations in Kuwait.
Small Field Rejuvenation: Challenges, Lessons Learnt & Redevelopment Concept
Authors: Kueh Jing Zhi , M Dimyati Umar Islam , Wan Mat Syarifah Suliza , Michael Kennedy Macvirick , M Fadhil M Imran , Dolah Khairul Arifin 
Published: October 2018

Abstract
Field D is located in offshore Sarawak, Malaysia. It was discovered in 1980s, and achieved first oil in 2012. Field D is categorized as small field, due to small reserves. In order to minimize development cost, Field D development utilized refurbished platform, tied back to Field A Complex, which act as central gathering facilities for nearby fields' production. Post drilling, Field D oil production was stabilized at around 1800 barrels of oil per day (bopd). Original field life was expected to be eight (8) years, as per original PSC expiry in 2021.
In 2014, Field D PSC was extended to 2034. With the new PSC, a team had been established to study Field D potential with the objective to extend Field D life to the new PSC expiry. In order to de-risk Field D redevelopment, the team reviewed existing wells drilled in Field D, and conducted production enhancement to increase Field D production before infill drilling commenced. The team had overcome various surface and subsurface constraints in redeveloping this small field: limited facilities, production capacity limit, compartmentalized reservoir, and fluid type & fluid contact.
Field D infill drilling campaign in 2017 yielded positive results, and field production post drilling had been sustaining at 6000 bopd since. This paper chronicles Field D journey, from initial development to field redevelopment. It will benefit operators who are looking to redevelop their small field and maximize field recovery.
Kinetics Analysis Validation for In-Situ Combustion by Coupling Experimental Data with Analytical Methods
Authors: Ismail Norasyikin Bte , Siu John , Hascakir Berna 
Published: October 2018

Abstract
The complicated nature of combustion reactions makes the performance prediction of in-situ combustion difficult. This study proposes a solution to better understand the complex chemical reaction schemes through systematically conducted Thermogravimetric Analysis and Differential Scanning Calorimetry (TGA/DSC) experiments.
In this study, results from combustion tube experiments (CTE) are integrated with kinetic and analytical modeling. The SARA (Saturates, Aromatics, Resins, and Asphaltenes) fractions of a bitumen sample were subjected to TGA/DSC experiments under air injection at a constant heating rate. Heat flow curves (DSC curves) were used to determine kinetic parameters by using Reaction Kinetic Models (Arrhenius Model, Coats-Redfern Model, Horowitz-Metzger Model, and Ingraham-Marrier Model).
The kinetic analyses conducted on separate SARA fractions and on bulk crude oil samples provided valuable information: asphaltenes require the largest activation energy but generate the greatest amount of heat upon combustion. Saturates provide large amounts of heat, which proves their ignition feature. Aromatics and Resins play an important role on asphaltene cracking, in addition to supplying large amounts of heat to asphaltenes upon burning.
In-situ combustion is a very promising enhanced oil recovery method which can yield high oil recovery. However, the unknowns associated to chemical reactions inhibit the prediction of combustion performance. This study provides a unique solution to find the correct and simple reaction kinetics by integrating reaction kinetic experiments with several kinetic analysis methods.
High-TDS Produced Water-Based, Low-Damaging Fracturing Fluids for Applications at 300°F or Higher
Authors: Li Leiming , Saini Rajesh , Mai Nam 
Published: October 2018

Abstract
Water usage in hydraulic fracturing jobs has been increasing continuously, mostly due to multistage hydraulic fracturing of horizontal wells in unconventional reservoirs. Meanwhile, nearly 100 billion barrels of produced water, often with total dissolved solids (TDS) higher than seawater, is being generated every year from oilfield operations. Operating cost could be lowered if produced water is used in place of fresh water in fracturing activities, due to the reduced fresh water consumption and produced water disposal cost.
Formulating slickwater or linear fracturing fluids with high-TDS produced water is a common practice. Crosslinked fluids have also been prepared with salt and hard produced water for medium and low temperature applications. At elevated temperatures above 250°F, it becomes much more challenging to make stable crosslinked fluids with untreated produced water due to the damage caused by the high water salinity and hardness. Without resorting to scale inhibitors and/or high fluid pH, fracturing fluids prepared with untreated high-TDS produced water have so far shown stability at around 275°F.
With careful selections of the fluid additives, a new high-temperature fracturing fluid system was recently formulated with untreated produced water having TDS at or above 295,000 mg/L. Made up of metal-crosslinked polysaccharides, the fluids were stable at high temperatures of 300°F or more. In representative tests, the fluid viscosity stayed above 100 cP (at 100 s−1 shear rate) for 2 hours at 300°F. To reduce the scaling tendency and enhance the gel cleanup, the fluid pH was suppressed to 7.2 or below as measured at surface temperature, resulting in a regained permeability of 77% in the conductivity test. Overall, the new produced water-based fluid system showed satisfactory performances at 300°F in fluid viscosity and stability, regained conductivity, and scaling tendency.
The key roles played by the additives to render the fluid stability at 300°F will be discussed for the high-temperature fracturing fluids prepared with high-TDS produced water, and the laboratory test results will be presented in detail.