bluuebunny/crossref_metadata_2025_split huggingface dataset:
Carmon Creek Thermal Field Development Project
Authors: Vannaxay David , Wasden Frederic , Howell Benjamin 
Published: October 2014

Abstract
Carmon Creek is Shell's Heavy Oil In-Situ thermal field development project in Peace River, Alberta, Canada. The Peace River Lease contains some 10 billion barrels of bitumen in-place at a depth of 600 m with viscosity as high as 100,000 cP. The Carmon Creek Phase 1&2 facilities, targeting a subset of this resource, are planned to start-up in 2018 and include oil treatment at 80,000 bod, produced water recycling and steam generation at 50 kt/d and electricity from co-generation at 600 MW. Over the project life-cycle, approximately 7000 dedicated wells (injectors and producers) will be drilled.
The Carmon Creek development concept is a combination of cyclic steam stimulation (CSS) and vertical steam drive (VSD) utilizing vertical and deviated wells in inverted 7-spot patterns at a well spacing of 115m (or 2.8 acres). Produced and imported gas is burnt to generate steam and electricity in co-generation facilities. Electricity is exported to market. After transfer of the thermal energy in the steam the bitumen viscosity is reduced sufficiently enabling production via conventional beam pumps. The produced emulsion is separated into gas, oil and water for treatment in the central processing facilities. Acid gas consisting CO2 and H2S is re-injected to deep disposal and the remaining treated produced gas burned in the co-generation facilities. Treated bitumen is mixed with diluents for pipeline export. Steam generation is fed by recycled water with excess water stored in a saline aquifer, which can be back-produced as needed.
This paper provides an overview of the main aspects of the field development, the challenges related to project delivery for a mega-thermal development and the solutions that were selected to address these challenges.
Computation of Three-Phase Capillary Pressure Curves and Fluid Configurations at Mixed-Wet Conditions in 2D Rock Images
Authors: Zhou Yingfang , Helland Johan Olav , Hatzignatiou Dimitrios G. 
Published: October 2014

Abstract
We present a three-phase, mixed-wet capillary bundle model with cross-sections obtained from a segmented 2D rock image, and apply it to simulate gas invasion processes directly on images of Bentheim sandstone after two-phase saturation histories consisting of primary drainage, wettability alteration and imbibition. We calculate three-phase capillary pressure curves, corresponding fluid configurations and saturation paths for the gas invasion processes and study the effects of mixed wettability and saturation history by varying the initial water saturation after primary drainage and simulating gas invasion from different water saturations after imbibition. In this model, geometrically allowed gas-oil, oil-water and gas-water interfaces are determined in the pore cross-sections by moving two circles in opposite directions along the pore/solid boundary for each of the three fluid pairs separately. These circles form the contact angle with the pore walls at their front arcs. For each fluid pair, circle intersections determine the geometrically allowed interfaces. The physically valid three-phase fluid configurations are determined by combining these interfaces systematically in all permissible ways, and then the three-phase capillary entry pressures for each valid interface combination are calculated consistently based on free energy minimization. The valid configuration change is given by the displacement with the most favorable (that is, the smallest) gas-oil capillary entry pressure. The simulation results show that three-phase oil-water and gas-oil capillary pressure curves are functions of two saturations at mixed wettability conditions. We also find that oil layers exist in a larger gas-oil capillary pressure range for mixed-wet conditions than for water-wet conditions, even though a non-spreading oil is considered. Simulation results obtained in sandstone rock sample images show that gas invasion paths may cross each other at mixed-wet conditions. This is possible because the pores have different and highly complex, irregular shapes, in which simultaneous bulk-gas and oil-layer invasion into water-filled pores occurs frequently. The initial water saturation at the end of primary drainage has a significant impact on the gas invasion processes after imbibition. Small initial water saturations yield more oil-wet behavior, whereas large initial water saturations show more water-wet behavior. However, in both cases, the three-phase capillary pressure curves must be described by a function of two saturations. For mixed-wet conditions, in which some pores are water-wet and other pores are oil-wet, the gas-oil capillary pressure curves can be grouped into two curve bundles that represent the two wetting states. Finally, the results obtained in this work demonstrate that it is important to describe the pore geometry accurately when computing the three-phase capillary pressure and related saturation paths in mixed-wet rock.
Preventing Scale Deposition Downhole Using High Frequency Electromagnetic AC Signals from Surface to Enhance Production Offshore Denmark
Authors: Krag Anders , Fergusson Alasdair Macneil , Grainger Martin 
Published: October 2014

Abstract
Mineral scale deposition is a significant impediment to efficient operation of oil and gas facilities. Deposition control strategies include brine demineralisation, chemical inhibition and mechanical intervention. Mitigation costs are highest at offshore locations requiring well intervention and include significant production deferment. Hydrocarbon production in the Danish sector of the North Sea has a number of specific regional challenges as reservoirs are often carbonate with high produced water calcium concentration resulting in a high potential for carbonate scaling. Secondary production techniques such as water injection flooding to maintain pressure are used and sea water is pumped directly into the reservoir introducing sulphate leading to downhole mineral scale deposition of barium sulphate, strontium sulphate etc. The offshore location of production facilities dictates that interventions are expensive and put pressure on valuable offshore bed spaces.
This paper reports results of field application of a recently introduced scale control technology based on high frequency electromagnetic AC signals generated and impressed onto a well head or associated piping conduit. Field trial data is provided from a production well with a history of scaling where production pressure was held back to reduce scaling severity. Field trial data describes the impact of the technology in preventing scale in a high value well. Analysis of the results showed that physical treatment using this alternative approach effectively controlled scale deposition such that the production systems was protected and the production benefits included increased reliability of gas lift valves, cessation of any tubing acid washes and enhancing production. The economic value added and reduction in risk to personnel and emissions are described.
An extended (9 month) pilot test has allowed production to be increased and no mineral scaling has been detected. The results achieved are promising. Stable and no lost production added a value to the producing asset and avoided significant revenue loss to the operator.
Staying the Course with Safely Delivering the Challenges and Opportunities Represented in Subsea Tieback Portfolio in the Gulf of Mexico
Authors: Sharma G. , Moss D. 
Published: October 2014

Abstract
This paper discusses the unique opportunities and strategies for successfully delivering Health, Safety, and Environmental (HSE) performance for Shell's Gulf of Mexico (GoM) Subsea Umbilicals Risers & Flowlines (SURF) Brownfield projects. Successful safety performance is evidenced by the 3+ years of zero recordable incidents for these projects.
The GoM SURF Brownfield projects constitute a portfolio of subsea tiebacks, each with the purpose of bringing new production to existing assets. Although typical project size is less than comparable Greenfield opportunities, these projects carry a high degree of technical and non-technical complexity. Managing the interface between the project and the existing asset, schedule dynamics inherent with multiple Mobile Offshore Drilling Units (MODUs), fragmented project delivery teams comprised of relatively junior staff, and high economic imperatives of project delivery present unique HSE challenges in the tie-back arena.
This paper will present the SURF Brownfield project execution model, which has increased the potential for safe, predictable, and efficient project delivery. Development and deployment of high performing project delivery teams and product delivery lines will be elaborated upon as a key enabler for safe and predictable project delivery. There will also be a discussion on how standardizing the work process supports consistent delivery of safe and predictable project outcomes. Finally, there is information on how the standardization was conceptualized and executed for effective implementation in the SURF community.
Novel Dynamic Diversion Applied in Stimulation of Shale Plays in North Mexico
Authors: Valenzuela A. , Parra P. A. , Gigena L. D. , Weimann M. I. , Villareal R. , Acosta N. L. , Potapova E. 
Published: October 2014

Abstract
In 2010, exploration of gas-rich and possible liquid-rich shale reservoirs began in northern Mexico. The initial challenges as in any exploration project were to demonstrate the availability of reserves and set the foundation for future development of plays. Wells were aimed at the upper cretaceous Eagle Ford formation and at the Jurassic Pimienta formation. While exploration campaign continues, the first development wells have been drilled in some areas. A total of 19 horizontal wells have been drilled and completed by January 2014.
The wells drilled in the latest stage of the exploration campaign in the Pimienta formation presented additional complexity, which led to an undesired trend of increased costs and extended completion times. Also, some of the wells drilled and completed during an earlier stage of the exploration campaign showed a rapid decline in production which directly threatened future development plans. To reverse these trends, a novel dynamic diversion technology for hydraulic fracturing treatments was implemented with positive results. This technology improves distribution of hydraulic fracturing treatments along the horizontal section of the wells, therefore allowing the stimulation of longer perforated intervals at once, ensuring that a great majority of the perforated clusters are efficiently stimulated. The need for mechanical plugs, to isolate the different hydraulic fracturing stages in the wells; the risk associated with pump down of plugs and milling times to remove these plugs were greatly reduced, which results in improved completion times and costs.
This study presents four case histories in which the technology was applied. One of the cases refers to re-fracturing operations of the last 3 stages in a well with a horizontal section of approximately 1,500m which was initially stimulated with 17 hydraulic fracturing stages. The remaining cases refer to the completion of three exploratory wells in which the horizontal section was stimulated with multiple hydraulic fracturing stages using the dynamic diversion technology. The treatments were evaluated using different techniques which mainly included: radioactive tracers and pressure response analysis. Initial results showed evidence of diversion both in pressure response and tracer log analysis, as well as stable production after stimulation. Interpretation of radioactive tracer logs and numerical production forecasting results confirm effectiveness of methodology applied.
The application of this technology can lead to a significant improvement in the efficiency of completions and effectiveness of stimulations of unconventional reservoirs in Mexico and around the world.
Phase Behavior Modeling and Flow Simulation for Low-Temperature CO2 Injection
Authors: Pan Huanquan , Chen Yuguang , Sheffield Jonathan , Yih-Bor Chang , Zhou Dengen 
Published: October 2014

Abstract
CO2 injection into an oil reservoir at low temperatures (less than 120 °F) can form three hydrocarbon phases, i.e. a vapor phase, an oil-rich liquid and a CO2-rich liquid phase. Most available reservoir simulators cannot handle three-hydrocarbon-phase flash, and the use of two-phase flash may cause significant numerical instability. The issue has been recognized in the industry for a long time. Studies to include three-hydrocarbon-phase flash in compositional simulations exist in the literature. However, this approach results in substantial increases of model complexity and computational cost, thus it may not be realistic for practical applications (at least for now). In this work, we propose a new PVT modeling procedure to eliminate the three-hydrocarbon-phase region for reservoir fluid/CO2 mixtures at low temperatures, and study its implication on flow simulation. In our method, the acentric factors of pseudo-components are adjusted to eliminate the three-hydrocarbon-phase region, which was not considered in any of the previous studies. Then, the experimental data for reservoir fluid PVT, CO2 swelling test, and MMP are also matched by further adjusting binary interaction coefficients, volume shift parameters and critical volumes of the pseudo-components. The procedure is applicable for cases with relatively small three-phase regions (e.g., some fields in west Texas), and can be applied with any PVT simulation software, and conventional two-hydrocarbon-phase simulators. The method is considered for two sector models from oil fields in west Texas, with fine-scale (more than 600,000 grid blocks) and up-scaled models. Compared to the standard characterization, in which the three-hydrocarbon phases exist, the new fluid model significantly improves the stability of flow simulation, demonstrating the robustness and efficiency of the new procedure. The method can be viewed as a practical approximation to field-scale simulations of the CO2 injection at low temperatures.
New Analytical Method to Calculate Matrix- and Fluid-Corrected Total Porosity in Organic Shale
Authors: Ortega(ConocoPhillips) Edwin , Torres-Verdín Carlos 
Published: October 2014

Abstract
Estimation of total porosity from neutron and density porosity logs in organic shale (source rock) is challenging because these logs are substantially affected by fluid and matrix-composition effects. Conventional interpretation of neutron and density porosity logs often includes corrections for shale concentration in which the main objective is to improve the calculation of non-shale porosity in hydrocarbon-bearing zones. Neutron and density porosity readings across shale zones are typically averaged using the root-mean-square (RMS) method.
We introduce a new and simple analytical expression for total porosity that effectively separates both matrix and fluid effects on neutron and density porosity logs. The expression stems from a new nonlinear mixing law for neutron migration length that is coupled with the linear density mixing law to calculate total porosity and fluid density. The method is applied in two sequential steps: first, separate corrections for only matrix effects are implemented to enhance the neutron-density crossover for qualitative interpretation of fluid type. Next, the coupled equation is used to estimate fluid density and actual porosity devoid of matrix and fluid effects. Calculated porosity and fluid density can be further used to calculate water saturation from density logs. One remarkable feature of this method is the ease with which it can be applied to obtain accurate and reliable results. Application of the method only requires knowledge of single-component nuclear properties and mineral volumetric concentrations. Nuclear properties can be obtained from a set of charts for multiple fluid types and minerals provided in this paper, while mineral concentrations can be calculated based on available triple combo logs or gamma-ray spectroscopy logs.
Two synthetic and four field examples (two conventional and two shale-gas reservoirs) are used to test the method. Firstly, we describe an application in a conventional siliciclastic sedimentary sequence where only shale concentration calculated from gamma-ray logs is required to improve the estimation of porosity in shaly sections. Second, we document several applications in which gamma-ray spectroscopy logs are used together with a reliable hypothesis for clay type to define mineral properties. Results compare well to NMR and core measurements, and the new method outperforms the conventional RMS procedure, especially in the cases of gas-bearing, low-porosity organic shale. The new analytical method can be readily implemented on an Excel spreadsheet and requires minimal adjustments for its implementation.
Natural Fractures in Unconventional Shale Reservoirs in US and their Roles in Well Completion Design and Improving Hydraulic Fracturing Stimulation Efficiency and Production
Authors: Li Bingjian 
Published: October 2014

Abstract
Most of the shale reservoirs in US land are naturally fractured. The fracture intensity and types vary from one shale to another. Even within the same shale in the same field, the heterogeneity of fracture intensity can be often expected to be high in a horizontal well. The current popular geometrical completion design can potentially ignore the existence of natural fractures. Hence, maximizing stimulation efficiency without understanding existing natural fractures can be a challenge. In this paper, study was made of the majority of the published case studies related to natural fractures in the US shales in the last 20 years. The evidence of natural fractures from either outcrops or subsurface data, i.e. core, borehole images, or other data is summarized for each studied shale. The latest studies show that the hydraulic fracture propagation can be strongly influenced by existing natural fractures regardless of whether they are open or closed. The roles of existing fractures in the shales include: 1) providing enhanced reservoir permeability for improved productivity if they are open and effectively connected by hydraulic fractures; 2) promoting much better fracturing network complexity regardless of whether they are open or closed prior to the stimulation; 3) giving possible negative impact sometimes, i.e. high water cut, if they are connected with wet zones below or above the reservoirs. It can be concluded that engineered completion designs that employ accurate knowledge of natural fracture data, in-situ stresses, and other reservoir and completion quality indicators as inputs can provide opportunities for enhancing stimulation efficiency and fracturing network complexity. This in turn can lead to better connectivity to a larger reservoir volume and access to more drainage area in the shales.
Introduction
The US shale gas story actually featured natural fractures. William Hart, a local gunsmith, drilled the first commercial natural shale gas well in US in Fredonia, Chautauqua County, NY in 1821, in shallow, low-pressure rock with fractures[1] [2]. The well was first dug to a depth of 27ft in a shale which outcropped in the area, then later drilled to a depth of 70ft using 1.5 inch diameter borehole. The produced gas was piped to an innkeeper on a stagecoach route[1]. Then the well was produced without any stimulation for 37 years until 1858 when it supplied enough natural gas for a grist mill and for lighting in four shops. It was a combination of the idea from Mr. Hart to drill the well and the presence of the natural fractures in the gas shale that made the 1st commercial shale gas discovery possible in shale gas history.
Experimental and Analytical Core and Geomechanical Data Analysis of a Tight Oil Carbonate Formation
Authors: Islam Arshad , Ziarani Ali S. , Cui Albert , Ehlers Silas , Schneider Brian 
Published: October 2014

Abstract
Unconventional resources around the world and particularly in North America have been revitalized as a result of advancements in hydraulic fracturing and horizontal wellbore technology. This has created a new wave of hydrocarbon exploration, exploitation and development in most of the tight hydrocarbon plays in western Canada. The multidisciplinary (geochemistry, geomechanics and geophysics) approach and the use of nanotechnology in the petroleum industry have not only helped us to improve our knowledge and understanding of these tight and complex reservoirs and their associated systems, but have also resulted in an upsurge of hydrocarbon recovery.
This study focuses on the results of several analyses performed on different core samples from the Swan Hills Formation, which is predominantly a calcium carbonate oil reservoir in the Western Canadian Sedimentary Basin. Routine and special core analyses of the core plugs were conducted to determine reservoir properties, including bulk and skeleton density, porosity by helium pycnometry, and pore size distribution by mercury injection capillary method (MICP). Stress-dependent permeability of the rock (matrix) was measured using the pulse decay permeability method. Triaxial compression tests were also conducted to determine the Young's modulus and Poisson's ratio, compressive strength, and residual strength after peak failure. Linear Mohr–Coulomb failure envelopes (cohesion and friction angle) were also constructed for the intact rock and the rock after failure. Furthermore, short-term and long-term conductivity of acid etched fractures were measured.
Empirical and theoretical correlations were used to model short- and long-term stress-dependent acid fracture conductivity. Nierode-Kruk's model was found to best fit the laboratory data among all models. Constants in Nierode-Kruk's model that depend on rock embedment strength and dissolved rock equivalent conductivity are reported. Effects of different acid concentrations on permeability and conductivity were discussed in detail. Creep testing was performed to determine time-dependent deformation of samples under confining stress. It was found that creep strain is dominated by primary creep stage. Time-dependent creep deformation is minimal for tested samples under various confining pressures. Mineralogy, rock fabric and wormhole growth were investigated using X-Ray Diffraction (XRD), Scanning Electron Microscope (SEM) and Computed Tomography (CT) scanning techniques.