bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hole Cleaning Performance of Water vs. Polymer-Based Fluids Under Turbulent Flow Conditions
Authors: Bizhani M.. , Rodriguez-Corredor F. E. , Kuru E.. 
Published: May 2015

AbstractThe problem of solid cleanout in horizontal wellbores is studied experimentally. The special case of drilling fluid circulation with no inner pipe rotation is considered. This case is similar to Coiled tubing drilling where often hole cleanout must be performed. Sand sized cuttings (ranging from 260 micron to 1240 micron) are used. Critical velocity and wall shear stress required for initiating bed erosion are measured. Water and viscous polymer base fluids with 3 different polymer concentrations are used.Results have shown that water always initiate cuttings movement at lower flow rates than polymer solutions. Fluids with higher polymer concentration and hence with higher viscosity required higher flow rates to start eroding the bed. Critical wall shear stress is also determined from pressure loss measurements. Analyzing the data revealed that water initiate cuttings removal at lower pressure loss than more viscous fluids. Higher viscosity fluids always showed higher pressure loss at the initiation of bed erosion.For the range of cuttings size studied, results show that intermediate cuttings size is easier to remove. Smallest and largest cuttings are more difficult to move requiring higher flow rates and higher pressure losses.Dimensionless analysis of relevant parameters to the process of cuttings movement is performed. It is shown that dimensionless wall shear stress (in the forms of Shield's stress and also ratio of shear velocity to settling velocity) correlates well with particles Reynolds number. Based on this finding two correlations are developed to predict wall shear stress required for initiating cuttings movement under different conditions.
Continuous Environmentally Efficient Pipeline Leak Detection
Authors: Rahmes Mark , Bingman Tasha , Blue Mark , Lemieux George 
Published: May 2015

Abstract
High-resolution sensors provide essential information to the oil and gas industry when planning for corridor right-of-way, land restoration, damage prevention, risk management and emergency response/damage prevention. The world's growing need for energy has put pressure on the remote sensing community to create even higher resolution and more accurate sensors than ever before. The location of the area of interest where remote sensing is needed is often based on the location of potential petroleum reserves. Political, terrain and weather conditions often determine the choice of technology used to collect the necessary data. Continuous pipeline monitoring is becoming increasingly critical for the oil and gas industry, which faces new challenges due to higher demands for energy. This paper presents the design, development and testing of a smart, wireless sensor network for early leak detection in oil pipelines, based on sensor measurements. Today's low power sensors are capable of measuring pressure, temperature and flow changes due to leaks. We describe a system model for determining decision-making strategies based upon the ability to perform data mining and pattern discovery by utilizing sensor information to detect leaks or abnormal situations. We discuss the development of a method for determining actionable information using game theory. We focus on applying probabilistic models to leak detection and geospatial tools for assisting emergency response and pipeline repairs. Probabilistic predictions are critical in practice on many decision-making applications. However, applicability to big data is complicated by the difficulties of inference in complex probabilistic models, and by computational constraints. Copyright 2015, Society of Petroleum Engineers
A Successful Post Completion Sand Control Method Used in Thermal Enhanced Oil Recovery Operations at the Kern River Field in Bakersfield, CA
Authors: Franks Spencer , Wise John , Rodriguez Sam , Hay Harold , Sanchez Fred , Ripley Mike , Erlendson Bill 
Published: May 2015

Abstract
The Kern River Field is one of the oldest continuous producing oil fields in North America. The field was originally discovered in 1899 and today comprises more than 10,000 active producing wells. The API gravity of oil in this field ranges between 11-13 degrees, and the operator employs thermal enhanced oil recovery methods in the form of continuous and cyclic steam (CS) injection. Rod pumping systems are the most common method of artificial lift utilized in this field. The most prevalent subsurface failure event realized by the operator is a sanded/seized (S/S) pump. More than fifty percent of all subsurface failures are associated with sand production. This paper will outline the use of resin injected during a cyclic steaming event (CS), down the casing annulus or tubing, in order to consolidate sand grains in the formation and reduce the potential for the influx of sand while a well is on production. In 2013 a project team was formed to pilot this sand control method at the Kern River Field. Candidates for this treatment were selected based on the frequency of sanded/seized events and reported wellbore integrity. Through this pilot, the project team was able to extend meantime between failure (MTBF) and achieve incremental oil production. The use of resin injected during a cyclic steaming event (CS) can improve well reliability and enhance well economics of marginal oil producers by providing an alternative to more expensive remedial options.
Remediation of Channeled Wells and Completions of Infill Wells by Using Resin-Coated Proppant and Proppant Coated with Special Resins in an Unconsolidated Sandstone Reservoir
Authors: Kruse Gustavo , Puliti Raúl , Millan Santiago Perez , Best Rocío Ortiz 
Published: May 2015

Abstract
19° API gravity oil with a viscosity between 150 to 200 cp is produced from the “El Corcobo Norte” and “Cerro Huanul” fields (550 active producer wells and 330 active injector wells) located in the Neuquen basin, Argentina. The reservoir is an unconsolidated sandstone reservoir that has been producing since 2005 by combining two techniques: cold heavy oil production with sand (CHOPS) and conventional waterflooding. Water injection began approximately one year after the start of production of oil, and while an excellent production response to the injection well was observed, the continuing sand production generated deep wormholes that allowed for direct communication between the injector and producer in some wells, resulting in the total loss of oil production.
Beginning in 2011, different remediation techniques were tested from the injector wells to repair the “pipeline” to the producing wells, with variable results. The original remediation program consisted of two steps: 1) a treatment to reconstitute the porous matrix (TRPM) and 2) a conformance water-control treatment (WCT), which was not as effective and was eliminated in the following remediation treatments. TRPM allowed the operator to put back into production wells that had been shut in, and its design evolved to help reduce costs and continue the wells’ reactivation.
To achieve an estimated ultimate recovery (EUR) factor of 50% (it was at 35% between the primary and secondary recovery), an injection project including an alkali, surfactant, and polymer (ASP fluid) treatment was implemented to improve the fluid sweep efficiency in a mature area of the field having high water cuts (85 to 90%). This project included drilling infill wells to go from an inverted seven-spot to a direct five-spot pattern, reducing the acreage from 60 to 20 acres (Ac). In 2013, the infill wells were completed without CHOPS; instead, a fracpack with proppant coated with a curable liquid resin (CLR) resistant to high pHs (i.e., the ASP fluids) was used to help prevent a possible collapse of the reservoir in the near-wellbore and entrapment of the progressive cavity pump when the ASP fluid front passed through as it would remove the residual oil that holds the sand grains together. To date, this fracpack treatment appears to have achieved the objective.
Performance Evaluation of a Newly Developed Demulsifier on Dilbit Dehydration, Demineralization and Hydrocarbon Losses to Tailings
Authors: Kailey Ishpinder , Behles Jacqueline 
Published: May 2015

Abstract
Chemical demulsification is a cost-effective, convenient, quick, and efficient method for breaking water-in-diluted bitumen emulsions in oil sands processing. The industry is always seeking demulsifiers that act as effective dehydrators and demineralizers, minimize rag layer formation by controlling oil/water interface, and reduce the diluent/bitumen losses to tailings. In this paper, the performance of a newly developed demulsifier “Z” was investigated for its performance on dilbit dehydration, demineralization, and hydrocarbon losses to tailings and compared against the first and second generation demulsifiers “X” and “Y”, respectively. The dehydration and demineralization efficiencies of demulsifier “Z” are 2.0 and 7.6%, respectively, higher than demulsifier “Y” and 6.4 and 10.7%, respectively, higher than demulsifier “X” at 50 ppm dosage after 15 minutes of residence time. Demulsifier “Z” also works better on the diluent and bitumen losses to the underflow as compared to demulsifier “X” and “Y”. To find the reason why demulsifier “Z” performs superior to “X” and “Y”, the solids were collected from the original froth and the top, interface, and bottom fractions of the diluted froth for characterization by X-ray diffraction analysis (XRD), X-ray energy dispersive spectrometry (EDS), scanning electron microscopy (SEM), and particle size distribution (PSD). XRD data shows that demulsifier “Z” reduced the amount of clays, iron, and zirconium oxide minerals from the top and interface dilbit fractions as compared to the control sample. PSD data shows that demulsifier “Z” reduced most of the particles of size less than 0.50 µm from the interface. Thus, demulsifier “Z” helps to resolve the interfacial material by separating the minerals that tend to form rag, especially siderite, pyrite, magnetite, rutile and anatase, from the oil/water interface and sends them to the underflow.
A Method to Calculate In–situ Water Relative-Permeability Using the Response at Observation Well Adjacent To Steam-Assisted-Gravity-Drainage Well-Pairs
Authors: Irani Mazda 
Published: May 2015

Abstract
Although convective heat flux is neglected in classic steam-assisted gravity-drainage (SAGD) models such as the one derived by Butler, heat convection through the condensate flow into porous media can be very important. A key control on the condensate flow is the in-situ relative-permeability to water within the reservoir. To date there is no methodology that can calculate the in-situ relative-permeability to water in SAGD reservoirs during steam injection and progression of the steam chamber. The in-situ relative-permeability to water during steam injection can be different from laboratory and well-test results. The problem with the results from lab test is that they are mostly from disturbed cores or remolded samples. And the issue with results from both lab and well testing is that at the edge of the steam chamber, bitumen undergoes thermal expansion of some 15%; therefore, unless the water saturation increases by a similar amount, water mobility is quickly decreased by the expanding bitumen phase. A method is provided to calculate in-situ relative-permeability in oil sand reservoirs using the distance between pressure and temperature response at the same depth. The implementation of the concepts is tested for Underground Test Facility (UTF) project. The results suggest that the in-situ relative-permeability to water during steam in most SAGD projects is limited to 10-4 to 10-5 and having higher relative permeabilities is only possible at lean zones. This paper describes a new method for reservoir characterization based on water mobility for different oil sand projects.
Reactive Steam Assisted Gravity Drainage Oil Sands Recovery Process
Authors: Khansari Z. , Gates I. 
Published: May 2015

Abstract
To extract oil from oil sands reservoirs the techniques are required that reduce the viscosity from hundreds of thousands and several millions of cP to a point that it can flow. In Steam-Assisted Gravity Drainage (SAGD) process, injected steam releases its latent heat and reduces the viscosity of the oil. This oil, referred to as bitumen, encountered steam-oil reactions process leading to aquathermolysis and steam-rock reactions - geochemical reactions. Geochemical reactions are responsible for in situ gas production and alteration of produced water composition that can affect the reservoir pressure, porosity, permeability, bitumen viscosity and thus the recovery process. In this research it has been examined that how water composition changes during SAGD operation. A reaction model was defined expressing the geochemistry of SAGD within the formation and a reactive thermal reservoir simulation was built to represent reservoirs with different shale layer geometries at various distances from SAGD wellpair. For the first time, the results demonstrated that the produced water composition can be used to detect baffles and barriers and their distances from wellpair. The analysis of produced water can be used as a tool to monitor the process dynamics and understanding the reservoir heterogeneity.
The Impact of Asphaltene Precipitation and Clay Migration on Wettability Alteration for Steam Assisted Gravity Drainage (SAGD) and Expanding Solvent-SAGD (ES-SAGD)
Authors: Kar Taniya , Yeoh Jun Jie , Ovalles Cesar , Rogel Estrella , Benson Ian , Hascakir Berna 
Published: May 2015

Abstract
This paper examines the wettability change during Steam Assisted Gravity Drainage (SAGD) and Expanding Solvent - SAGD (ES-SAGD). The qualitative and the quantitative analyzes of residual oil for steam and steam-solvent coinjection cases are achieved to investigate the impact of clay migration and asphaltene precipitation on wettability alteration. The solvent selection in ES-SAGD is made according to their solubility in asphaltenes; insoluble (n-hexane), soluble (toluene), and intermediate soluble (cyclohexane). Five experiments (one SAGD and four ES-SAGD) are conducted on a Canadian bitumen. Different solvent injection strategies are followed: coinjection and cyclic injection. Wettability is determined through contact angle measurements on the spent rock samples for both inside and outside steam chamber zones. Residual oil saturation is defined via solvent extraction and with a thermal method; Thermogravimetric Analysis (TGA). Two solvents are used for the extraction: toluene and mixture of 90%dichloromethane+10%methanol. The asphaltene fractions of the residual oil samples are further characterized by determining clay content, Solubility Profile; and carbon, hydrogen, sulfur, nickel, and vanadium contents. Both the thermal and the two solvent extraction methods yield more or less the same residual oil saturations. The asphaltene content of the residual oils (22 to 27 wt%) is found lower than the asphaltene content of original bitumen (34 wt%). However, higher metal content is detected on the residual oil asphaltenes. Analysis of residual oil asphaltenes shows a significant presence of clays in the inside steam chamber region for SAGD, which inhibits effective steam chamber propagation by reducing permeability. This asphaltene-clay interaction increases the oil- wetness of the rock surface and impacts the oil production adversely. However, this effect is minimized by the addition of solvents. The wettability measurements on spent rock samples also support these findings. The elemental analysis of asphaltenes reveals that with the increase in precipitation of asphaltenes (for ES-SAGD with n-hexane), there is an increase in vanadium and nickel concentrations. In terms of asphaltene Solubility Profiles, higher polarity was found for asphaltenes originated from inside the steam chamber zone for ES-SAGD with n-hexane, where the effect of n-hexane in the vapor phase is dominant. This work shows that the effectiveness of ES-SAGD may be in part caused by contributions from wettability changes, clay migration, and asphaltene precipitation in addition to by oil viscosity reduction alone. This study provides information on the interaction of clay, asphaltenes, solvent, and steam during SAGD and ES-SAGD. It explains the behavior of clay and asphaltenes during SAGD and ES-SAGD when different solvents are used.
Reservoir Simulation of H2S Production During a SAGD Process Using a New Sulfur-Based-Compositional Kinetic Model
Authors: Ayache Simon V. , Lamoureux-Var Violaine , Michel Pauline , Preux Christophe 
Published: May 2015

Abstract
Nowadays steam injection is commonly used as a thermal EOR method due to its efficiency for recovering hydrocarbons from heavy oils and bitumen. Reservoir models simulating this process describe the thermal effect of the steam injection, but generally neglect the chemical reactions induced by the steam injection. These reactions are called aquathermolysis and have been previously investigated through laboratory experiments. Based on these experimental results, this paper proposes a new compositional kinetic model to reproduce these reactions in the context of reservoir modeling. In particular the proposed reactions model accounts for the formation of the highly toxic and corrosive acid gas H2S in the presence of sulfur-rich heavy oil and predicts the modification of the oil SARA composition versus time that results from the aquathermolysis reactions. The overall objective of this paper is to understand the aquathermolysis reactions in reservoir undergoing steam injections and to provide the Oil companies with a numerical model for reservoir simulators that forecasts H2S production risks.
The new Sulfur-Based-Compositional Kinetic Model is firstly presented and then validated in the context of laboratory-scale experiments. Its H2S and SARA composition predictions are based on a new simplified reactive scheme of 5 reactions coupled to a compositional and thermal reservoir simulation with no mass transfer (0D). Finally the thermo-kinetic modeling is coupled with a 2D reservoir simulation of a SAGD process for a generic Athabasca oil sand. The H2S to SARA (bitumen) production ratio against time computed by the reservoir simulation is found to be consistent with data from a SAGD process in Athabasca, which validates the modeling approach followed.
Performance Step Change in Shallow Extended Reach Wells in Venezuela Enables Drilling Optimization and Increased Heavy Oil Production
Authors: Chamat Elias , Cuadros Guillermo , Trejo Ely , Scrofina Jose , Cermeno Elio , Rodriguez Oscar 
Published: May 2015

Abstract
In an operation in the Venezuelan Faja, well placement and rotary steerable systems (RSS) enabled drilling faster, longer, and shallower ERD wells than those that have been drilled with mud motors in the field over last 20 years. The results demonstrate a performance step change in this area.
Standard drilling in the Faja includes dogleg severity (DLS) requirements as high as 8°/100 ft and rates of penetration (ROPs) as fast as 2,000 ft/hr; these were perfect conditions for using mud motors to drill build sections and horizontal wells. As drilling in the Faja moved south, reservoirs at true vertical depth (TVD) from 1,200 to 1,600 ft started to be developed. Shallow reservoirs and even higher DLS made it inefficient to drill the long 4,000-ft extended reach sections planned as this requires multiple pipe swaps to redistribute heavy bottomhole assembly (BHA) components and wiper trips to clean the hole to allow weight-on-bit (WOB) transmission to reach the bit.
To reduce tortuosity, torque and drag, and stuck-pipe events; to improve hole cleaning, WOB transmission, and ROP; and to drill longer horizontal sections, a point-the-bit RSS was tried for the first time in Junin division. The first RSS well drilled in a shallow horizontal well exceeded all objectives and expectations set. Seven more horizontal sections drilled with the same RSS proved the system was robust enough to break a different drilling record on each well.
The current shallow extended reach well (SERW) record in the Faja was drilled with a mud motor to 1,231 ft TVD with 4,404 ft of horizontal section and a TVD versus horizontal stepout ratio of 1:4.4. Advanced drilling engineering, bed boundary mapping LWD technologies, RSS, and improved drilling practices in six horizontal sections enabled drilling to similar ERD ratios, while breaking records for ROP, horizontal section length, and drilling and completion speed at similar TVDs.
The performance step change in the Faja accomplished through the use of RSS and novel drilling practices has enabled increasing heavy oil production through drilling longer horizontal sections and through the reduction of mud filtrate and formation damage. The performance increase along with lesser tortuosity and friction factors have allowed drilling longer horizontal sections, saving valuable rig time, producing wells earlier, and running liners to total depth (TD) trouble-free unless stopped by oil production.
Type Curves for Cyclic Steam Operations in the Grosmont Saleski Pilot and Their Implications for Recovery Mechanisms
Authors: Yang D. , Hosseininejad M. , Stewart D. , Brand S. 
Published: May 2015

Abstract
Type curves that are developed for bitumen recovery from the Grosmont carbonate reservoir by cyclic operation of steam injection and production through a single horizontal well, consistently match field data, thereby confirming the validity of two key simplifying assumptions: heat flow is conductive; the heat capacity of the rock dominates: This is consistent with the low porosity and high heat capacity of dolomite. As a result, heat retention in the reservoir is efficient.gravity drainage dominates the recovery mechanisms: Thermal Assisted Gas-Oil Gravity Drainage (TA-GOGD) is the dominant recovery mechanism.
The type curve method is used to evaluate unrestricted reservoir performance by quantifying operational constraints and to forecast new cycles in the pilot operations.
Thermal Formation Damage and Relative Permeability of Oil Sands of the Lower Cretaceous Formations in Western Canada
Authors: Romanova U. G. , Ma T. , Piwowar M. , Strom R. , Stepic J. 
Published: May 2015

Abstract
Canada ranks third in the world in terms of oil reserves which are primarily heavy oil and oil sands. In situ production of heavy oil and bitumen by thermal methods based on steam injection is a commercial technology. However, as the availability of better quality deposits is declining, the industry is moving towards development of lower quality oil sands. Lower quality oil sands are typically finer, have lower initial oil saturation and a more complex mineralogy.
Thermal formation damage associated with steam injection is discussed in the paper in regards to oil sands located in the Lower Cretaceous formations in Western Canada. The focus of the paper is the McMurray, Clearwater and Grand Rapids oil deposits. Petrographic data (thin section analysis, X-ray diffraction and scanning electron miscroscopy) and physical rock properties are used to compare three oil sand formations. Results of laboratory experiments to obtain relative permeability data and evaluate thermal formation damage are discussed. Examples of the high temperature-high pressure water-oil relative permeability and steamflood data for three formations are presented. The paper shows that thermal formation damage is reservoir specific.
A multidisciplinary approach is needed to obtain a good understanding of oil sand deposits, in particular lowerquality reservoirs. Laboratory testing to evaluate formation damage effects and obtain relative permeability data is essential for reservoir simulation and feasibility studies for a specific project.