bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluating the HSE Risk Costs and Reputational Implications of Major Accident Hazards in E&P Activities
Authors: Petrone A. , La Rosa L. , Sordini E. , Scataglini L. , Dresda F. , Pavli E. , De Ghetto G. , Cherubin P. , Pellino S. , Bandini R. 
Published: June 2014

Abstract
The Cost of producing a barrel of oil depends on a variety of factors related to the inherent costs (direct and indirect) associated with oil field exploration, development, exploitation and lifecycle extension up to oil field decommissioning. Yet there are also other variables that enter this already complex equation and contribute to determine the final oil price.
Like any other industry, in the oil and gas business, accidents, have negative impacts on operational and financial performances, since they can adversely affect the production process and require proper restoring interventions.
Whenever people are injured, assets damaged, the environment polluted and business interrupted, money is unavoidably lost and company image and reputation is compromised. It is not easy to estimate the nature and extent of such losses and translate this estimate in a defined algorithm. However, different components can be evaluated through quantitative and qualitative methodologies.
Moving from these considerations, this paper presents a methodology aimed at evaluating the so called "Cost of the risk" of a Barrel of oil that takes into account the following elements:
Process Safety Risk Costs: to face the impact on people due to process Major accidents Occupational Risk Costs: to face occupational safety hazardous events Environmental Risk Costs: to address the impact on the environment due to a Blow out event or pipeline ruptures Asset Risk Costs: to manage the financial impact on the Asset due to process Major accidents Reputational risks costs: to manage potential impacts on reputation and negative perception of the public of the company
Environmental Stewardship: Global Applications of a Non-Radioactive Method to Identify Proppant Placement and Propped Fracture Height
Authors: Duenckel Robert J. , Palisch Terry T. , Han Xiaoganag , Saldungaray Pedro 
Published: June 2014

Abstract
Accurate assessment of intervals receiving proppant and the determination of near well bore fracture heights are valuable in assessing and optimizing stimulation strategies. Proppant placement evaluation in hydraulic fractures has traditionally involved the detection of radioactive tracers pumped down hole with the proppant. However, as environmental regulations regarding this technique have tightened, and with increased scrutiny by the public and regulatory bodies of the industry in general and hydraulic fracturing in particular, the need for an alternative to radioactive tracers has become paramount.
A new technology for assessing intervals receiving proppant and determining fracture heights utilizing a non-radioactive detectable proppant has been recently introduced. The technology has found global acceptance and has proven to be a robust and accurate method of locating proppant in the near well bore region. In addition to eliminating the safety and environmental concerns with radioactive tracers, this new method also provides a permanent indication of the proppant location near the wellbore. Unlike traditional radioactive tracers which must be logged before the radioisotopes completely decay, this new method will allow investigation of the proppant pack many years or decades in the future, which will provide critical information during remedial or redevelopment work that cannot be determined with conventional approaches.
A review of the current state of regulatory impediments to the use of radioactive tracers in key producing regions around the world is discussed highlighting the need for an alternative diagnostic technology. The technology utilized in the application of the non-radioactive detectable proppant is described and comparisons to other fracture diagnostic technologies are presented. Several case histories are shown which illustrate various applications of the technology in regions around the globe. These case histories include applications performed in Asia, Middle East, Europe and North and South America. In addition to identifying proppant location and fracture height, this technology can be used in other applications such as the evaluation of gravel pack quality. If the current trends in regulatory actions related to hydraulic fracturing continue, it is anticipated that the use of radioactive tracers will be restricted to fewer and fewer locales. At the same time the importance of reliable fracture diagnostics for optimization of hydraulic fracturing both from a well performance and cost control standpoint remains extremely important.
Polymer Flooding Pilot Learning Curve: 5+ Years Experience to Reduce Cost per Incremental Oil Barrel
Authors: Buciak J. , Sancet G. Fondevila , Del Pozo L. 
Published: June 2014

Abstract
This paper deals with the learning curve of a 5+ years polymer flooding pilot conducted in a mature water-flood that includes several works related to injector and producer wells, reservoir management, etc. The scope of this paper is to describe the learning curve during the last five years rather than the reservoir response of the polymer flooding technique; focus is on the aspects related to reduce cost per incremental oil barrel for a possible extension to other waterflooded areas of the field.
Diadema Oil Field is located in the San Jorge Gulf Basin in the Southern portion of Argentina. The field is operated by CAPSA, an Argentinean oil producer company; it has 480 producer and 270 injector wells. The company has been developing waterflooding during more than 18 years (today this technique represents 82% of oil production in the field) and produces about 1,600 m3/d of oil and 40,000 m3/d of gross production (96% water cut) with 38,400 m3/d of water injection.
The reservoir being polymer-flooded is characterized by high permeability (500 md average), high heterogeneity (10 to 5000 md), high porosity (30%), very stratified sand-stone layers (4 to 12 m of net thickness) with poor lateral continuity (fluvial origin) and 20 °API oil (100 cp at reservoir conditions).
Diadema's Polymer Flooding Pilot started in October 2007 on 5 water injectors (it includes 13 injectors today) with an injected rate of 1000 m3/d (today, 2000 m3/d). Polymer solution is made using produced water (15000 ppm brine) and 1500 ppm of HPAM polymer reaching 15/20 cp of fluid injection viscosity.
Oil rate production from the original "central" producers (wells that are aided with 100% of polymer injection) has increased 100% at the same time as average reduction in water cut is about 15%.
The main aspects presented in this work are: depth profile modification with cross-linked gel injected along with polymer, use of "curlers" to regulate injection in multiple wells with one injection pump without shearing the polymer and an improved technology on producer wells with PCP to decrease shutting time and number of pulling interventions.
The plan for the next years is to extend this project to other areas by using the acquired knowledge and to improve different aspects, such as water quality and optimization of polymer plant operation, among them. These improvements will allow the company to reduce operative cost per incremental oil barrel.
Distributed-Flux Burners Improve Life of Firetubes and Process Throughput in Heater Treaters
Authors: Bartz David , Silberstein Michael , Gotterba James 
Published: June 2014

Abstract
Polymer agents are being used to increase the yield of oil-sand reservoirs. While these polymers are effective in increasing yield, they present problems in heater treaters used for oil/water separation. In particular, the heavy oil and polymer emulsion can coat the outer surface of heater treater firetubes, creating an insulating layer that causes high wall temperatures of the firetube. This can lead to early failure of the firetube, causing costly shutdowns and repair.
The unique design of the distributed-flux burner solves this problem by providing uniform heat distribution over a greater area of the firetube compared to conventional burner technology. The burner utilizes premixed surface-stabilized combustion on a porous ceramic cylindrical surface. Heat release of the burner is kept constant along the entire burner surface. The burner is located in the center of the firetube along the tube axis, providing uniform heat distribution to the wall. This design significantly reduces the peak heat flux and film temperatures around the firetube found with conventional burners, which in turn reduces harmful thermal degradation of the firetube and coking of the oil mixture. Thermal analysis shows that for the same total energy input, the distributed-flux burner provides a 33% reduction in peak heat flux to the firetube wall compared to a conventional burner.
The distributed-flux burner technology has been successfully used in heater treaters in California and in asphalt heating tanks in Canada. This paper will present design data from a recent installation of the distributed-flux burner in a heater treater for a Canadian oilfield using polymer injection that had previously suffered frequent firetube failures.
A New Surveillance Method for Delineation of Depletion Using Microseismic and Its Application to Development of Unconventional Reservoirs
Authors: Dohmen T. , Zhang J. , Li C. , Blangy J. P. , Simon K. M. , Valleau D. N. , Ewles J. D. , Morton S. , Checkles S. 
Published: June 2014

Abstract
Hess Corporation performed microseismic monitoring of hydraulic fracturing in two infill horizontal wells in the Middle Bakken Play of North Dakota during 2011. Six vertical observation wells were drilled to monitor microseismic events. Each observation well was fitted with a pressure gauge in the Middle Bakken interval, capped by a bridge plug, and instrumented with 40 geophones. The experiment was specifically designed to observe the interaction of the fracs with a pre-existing Middle Bakken horizontal well, which had been on production for about two and a half years. The producing well was shut in for the duration of the experiment and instrumented with a downhole pressure gauge.
Experimental results show the hydraulic fracturing did not propagate as anticipated. Instead, the microseismic observations provided a very interesting result early during the stimulation of the first infill well. While fracturing the fourth stage of the first infill well, microseismic events appeared along the length of the nearby production well at distances up to 9,000 ft away from the open frac port. During this stage, and just prior to the appearance of the distant events, a pressure connection was established to the original well as recorded by the pressure gauge in that well. Our interpretation is that these microseismic events were distributed throughout the depleted zone surrounding the original production well. We provide evidence for the development of a cloud of depletion points through the use of pressure measurements, microseismic event speed plots, and Mohr's circle analysis.
This experiment provided a unique opportunity to "see" the shape of the depleted zone and to understand its influence in developing Bakken resources. By analyzing the outline of the depleted zone outline, we can now propose a series of reasonable infill well locations at a minimum distance from the original producer. We are leveraging microseismic as a tool to optimize the spacing of development wells. Our objective is to infill drill at the minimum distance required to maximize fracture contact in-zone near the infill wells and yet avoid significant overlap into previously depleted zones. Thus, a new application for microseismic monitoring is envisioned, in which one would pressure-up a producing well in order to measure its actual area of depletion prior to planning subsequent development wells and executing field-wide strategies for hydraulic fracturing.
sCore: A Mineralogy Based Classification Scheme for Organic Mudstones
Authors: Gamero-Diaz Helena , Miller Camron , Lewis Richard 
Published: June 2014

Abstract
In recent years, operators have produced large quantities of hydrocarbon from organic shale reservoirs. Horizontal drilling and multi-stage stimulations, targeting sections with superior reservoir quality (RQ) and completion quality (CQ), have been proven as key to their development. Organic mudstones, often referred to as shales, are fine-grained sedimentary rocks with total organic carbon (TOC) above 2% and typically complex mineralogy, consisting of a mixture of biogenic and terrigenous sources of siliciclastic and/or carbonate debris, affected by diagenetic processes. These rocks are highly heterogeneous especially perpendicular to bedding. Although numerous cores and outcrops have been studied and described, there is no published mineralogy-based classification scheme for organic mudstones. This paper defines a methodology for creating a detailed mineralogy-based description for organic mudstones using inorganic mineralogy, primarily X-ray diffraction (XRD) and geochemical log data.
The proposed classification scheme is based on a ternary diagram created specifically for organic mudstones by using a combination of core- and log-based mineralogical relationships. The primary classes are siliceous mudstone, carbonate-rich mudstone and argillaceous mudstone. Sub-classes are based on relative amounts of these three mineral groups. A mineralogy-based classification may help provide a better understanding of depositional conditions and identify target zones for completion. A common metric for the description of organic mudstones will also facilitate comparison of such reservoirs from different areas, formations, basins, and continents. A secondary objective is to provide a log display that flags other descriptive parameters that impact RQ, CQ and/or operational efficiency. A strong correlation exists between mineralogy and CQ in most U.S. shale plays. The correlation between mineralogy and RQ is not as strong. RQ appears to be driven by both compositional and textural components of organic mudstones. The log displays presented here provide a consistent description of the organic mudstone section and the input necessary for proper decision making when planning a drilling development project.
Correlation of Permeability for the Travis Peak Formation
Authors: Nzerem Vitalis , Civan Faruk 
Published: June 2014

ABSTRACT
Civan's power-law equation of permeability derived based on a bundle of leaky tubes model of tortuous flow paths in porous media is proven to describe a large amount of permeability and porosity data of the Travis Peak Formation in Northern Gulf Coast Basin of the U.S.A. Its parameters are shown to correlate consistently well with the cementation factor. It is demonstrated that these correlations can be used for prediction of permeability in the field.
Improved Prediction of Multi-Component Hydrocarbon Fluid Properties in Organic Rich Shale Reservoirs
Authors: Zhang Yijia , Civan Faruk , Devegowda Deepak , Sigal Richard F. 
Published: June 2014

Abstract
The fluid properties modifications in nanoporous systems produced by the effect of pore wall potentials and the limited number of molecules in nanopores are investigated for liquid-rich shales. These properties include phase behavior, interfacial properties, gas and liquid transport, storage, and composition. The existing theoretical equations are modified to predict the vapor-liquid equilibrium for shale and the unique behavior of fluids in kerogen and inorganic pores. The pore geometry, molecule size, interaction between the sorbed molecules and the nanoporous framework are included to enable accurate prediction of fluid phase behavior, critical properties, and composition. The predictions of the proposed approaches are compared to results obtained using bulk fluid properties. The implications of ignoring the role of pore proximity on fluid properties can potentially be severe and can potentially compromise estimates of drainage areas, well spacing, recovery factors and reserves.
Smart Gas Lift Valves Enhance Operational Efficiency of Offshore Wells
Authors: Xu Zhiyue , Richard Bennett M. , Kritzler James H. 
Published: June 2014

Abstract
In a conventional gas lift system, dummy valves are loaded in side pocket mandrels to isolate the annulus from the tubing where pressurization is required to test the tubing, test the annulus, set a hydraulic packer or activate an isolation device. Then for gas lift, wireline intervention would be required to remove the dummy valves and install the live gas lift string. This can be a long, cumbersome process that can damage existing infrastructure and delay production while new live valves are installed. This paper presents a smart gas lift valve with disintegrable nanostructured composite material technology. The valve is installed in the well to function as a dummy valve during completion operations and then convert from a dummy valve to a live valve through in-situ disintegration of a nanostructured composite plug in brine during cleanup process. This eliminates multiple slickline trips or well intervention costs to replace dummy valves with live valves and significantly increases completion operation efficiency of offshore wells. The nanostructured composite plug is high strength, is chemically resistant to drilling mud, is slightly reactive with fresh water and disintegrates within 12 to 50 hours in salt water. The smart gas lift valves were successfully installed in 42 new wells that were artificially producing with gas lift offshore Southeast Asia. The nanostructured material, the valve design, the lab test data and results from successful field tests will be presented.
A Case History of Comprehensive Hydraulic Fracturing Monitoring in the Cana Woodford
Authors: Lowe T. , Potts M. , Wood D. 
Published: June 2014

Abstract
In the Cana Field in Western Oklahoma, horizontal wells are completed with multiple hydraulic fractures to economically produce from the Woodford Shale. This field development program is relatively young, and previous fracturing optimization had been achieved by trial and error testing. Cana wells usually are drilled with a 5,000-ft lateral, which is hydraulically fractured in 10-20 stages utilizing the plug-and-perf method with multiple clusters per stage. Throughout the early field development, there has been significant uncertainty regarding various subsurface parameters including: fracture propagation geometry, cluster contribution, and interference remediation. This paper describes a comprehensive fracture monitoring project, which will be used to further the understanding of the hydraulic fracture geometry, interference, deliverability, and production.
In late 2012, the project well was drilled as part of the infill development program. In January 2013, the well was completed with a 12 stage slickwater frac. Several established and cutting edge technologies were used to assist with monitoring the hydraulic fracturing operation of the subject and offset wells. These technologies included: Distributed Temperature Sensing (DTS), Distributed Acoustic Sensing (DAS), prototype cemented frac valves, permanent bottom hole pressure gauge, surface micro seismic, down hole micro seismic, offset bottom hole pressure monitoring, logging-while-drilling, advanced open hole logging, radioactive tracers, and chemical tracers. These technologies were used successfully to monitor cementing operations, offset fracturing, monitor well fracturing, coiled tubing drill-out, flowback, and initial production. This project has assisted in the understanding of subsurface events and is expected to provide continued insight into long term production. Similar projects are being considered for the future, and this technology may ultimately become part of the standard completion.
This paper will focus on the planning, logistics, installation, and operation of this one of a kind monitoring project in the Cana Field.
Pressure Transient Tests and Flow Regimes in Fractured Reservoirs
Authors: Kuchuk Fikri , Biryukov Denis 
Published: June 2014

Abstract
Fractures are common features in many well-known reservoirs. Naturally fractured reservoirs consist of fractures in igneous, metamorphic, and sedimentary rocks (matrix). Faults in many naturally fractured carbonate reservoirs often have high-permeability zones and are connected to numerous fractures that have varying conductivities. Furthermore, in many naturally fractured reservoirs, faults and fractures can be discrete (rather than connected network dual-porosity systems).
In this paper we investigate the pressure transient behavior of continuously and discretely naturally fractured reservoirs using semi-analytical solutions. These fractured reservoirs can contain periodically or arbitrarily distributed finite- and/or infinite-conductivity fractures with different lengths and orientations. In some of our earlier papers, we showed that in terms of pressure transient, neither continuously nor discretely fractured reservoirs behave like the Warren and Root (1963) dual-porosity model. Unlike the single-derivative shape of the Warren and Root model, derivatives of pressure transient tests in fractured reservoirs exhibit more than 10 flow regimes. There are seven important factors that dominate the pressure transient test-flow regime behavior of fractured and faulted reservoirs; i.e., fractures and/or faults that: 1) intersect the wellbore parallel to its axis, with a dipping angle of 90° (vertical fractures), including hydraulic fractures; 2) intersect the wellbore with dipping angles from 0° to less than 90°; 3) are in the vicinity of the wellbore; 4) have extremely high- or low-fracture and fault conductivities; 5) have various sizes and distributions; 6) have high- and low-matrix block permeabilities; and 7) have damaged fractures (skin zone) due to drilling and completion operations and fluids. All flow regimes associated with these factors are shown for a number of continuously and discretely fractured reservoirs with different well and fracture configurations. For a few cases, these flow regimes are compared with those from the field data. History matchings of the pressure transient data generated by using our discretely and continuously fractured reservoir model with the Warren and Root (1963) type dual-porosity models are also presented.
Influence of Hydraulic Fractures on Wellbore/Sandface Temperatures During Production
Authors: App J. F. 
Published: June 2014

Abstract
The influence of hydraulic fractures during production is to alter the wellbore/sandface temperature changes by reducing the magnitude of the Joule-Thomson expansion effect. Compared to an unfraced completion in which the flow path of the reservoir fluids is purely radial, the presence of hydraulic fractures lengthens the flow path the reservoir fluids must take by creating a linear flow geometry. For a given drawdown, therefore, the local pressure gradients are lower in a hydraulically fractured completion compared to a non-hydraulically fractured completion. Through dimensionless analysis it will be shown that the Joule-Thomson effect is proportional to the local pressure gradient squared which implies a reduction in the Joule-Thomson effect for a hydraulically fractured completion compared to a non-hydraulically fractured completion. Simulations from a thermal reservoir/wellbore model will be presented comparing the thermal responses between hydraulically fractured and non-hydraulically fractured completions. It will be shown that the presence of hydraulic fractures can reduce the wellbore/sandface temperature changes by much as 85% compared to a non-hydraulically fractured completion. Additionally it will be shown that measurement of sandface and wellbore temperatures during production can provide information to determine which intervals have been successfully hydraulically fractured, and to a lesser extent a qualitative assessment of hydraulic fracture efficiency.