bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enumerating Permeability, Surface Areas, and Residual Capillary Trapping of CO2 in 3D: Digital Analysis of CO2CRC Otway Project Core
Authors: Knackstedt Mark , Dance Tess , Kumar M. , Averdunk H. , Paterson L. 
Published: February 2011

Abstract
In geological storage of CO2 there are four main trapping mechanisms; structural, dissolution, mineral and residual trapping. While structural and dissolution trapping depend on the large scale structure of the reservoir, both residual and mineral trapping are strongly influenced by geometry at the pore scale. The dominant mechanism for residual capillary trapping is snap off which depends largely on the interconnectivity of the pore space and ratio of the pore throats to pore bodies. Mineral trapping depends largely on the surface area and mineralogy of the rock. Digital core analysis makes it possible to directly enumerate the detailed pore and mineral phase structure of core material in 3D. Flooding experiments enable the amount and microscopic distribution of residual fluid phases to be directly imaged in 3D. In this paper the pore scale properties associated with mineral and residual capillary trapping are directly enumerated using core material from the CO2CRC Otway CO2 storage project in Australia. Surface areas associated with varying mineral phases are quantified. 3D pore network characteristics are derived from the image data which allow the quantification of the pore network structure (e.g., interconnectivity) and the pore geometry (pore/throat size, pore shape, aspect ratio). Heterogeneity of the permeability and anisotropy are calculated directly. The amount of residual non-wetting phase of analog fluid pairs is directly measured on Otway core material after flooding at the pore scale in 3D. The microscopic distribution of the residual non-wetting phase within the pore space is quantified and individual pore occupancies defined. This information will provide a better understanding of recovery mechanisms and assist in the design and implementation of CO2 flooding processes. Comparison of individual pore occupancies based on 3D image data provides a foundation for quantitative comparison of experiment to pore scale modeling and enable testing and calibration of pore network predictions of CO2 storage.
Pressure Buildup Test Analysis of a Gas Condensate Well in the Middle East
Authors: Al Ismail Maytham I. , Horne Roland N. 
Published: February 2011

Abstract
The deliverability of rich gas wells producing below the dew-point pressure is severely impacted due to condensate banking around the wellbore. Condensate banking also complicates the pressure transient test analysis due to multiphase flow and mixture composition change. The three-zone method to compute the two-phase pseudopressure gives more accurate reservoir properties than the single-phase pseudopressure method, because it accounts for the composition change in the reservoir. The three flow regions are: inner region 1 where gas and condensate flow simultaneously, middle region 2 where gas and condensate are present but only gas is mobile and outer region 3 where only gas is present.
In this work, three pressure build-up tests for a Middle Eastern gas-condensate well were history matched with a compositional simulator. First, the PVT test results of the reservoir fluid were simulated using Peng-Robinson equation of state. Then, the generated fluid model was included in a radial compositional model that considered the three flow regions. The compositional model was used to history match the pressure build-up tests by modifying the reservoir properties. Then, the generated pressure buildup tests were analyzed using three pseudopressure techniques for comparison: the single-phase pseudopressure, the two-phase steady-state pseudopressure and the two-phase three-zone pseudopressure.
Results indicated that all three pseudopressure techniques were capable of estimating permeability accurately. However, variations in skin estimations were observed. The three-zone pseudopressure approach was able to consistently estimate skin accurately because it always represented the pressure-saturation relationship around the wellbore correctly. On the other hand, both the single-phase pseudopressure and the two-phase steady-state pseudopressure were unable to estimate skin accurately. The skin effect due to liquid dropout caused the skin factor estimations by the single-phase pseudopressure approach to be high. Additionally, the steady-state method overestimated the pressure-saturation relationship which ultimately caused the skin estimates to be low for the steady-state pseudopressure approach.
Liquid Entrainment in Annular Gas/Liquid Flow in Inclined Pipes
Authors: Magrini K. L. , Sarica C. , Al-Sarkhi A. , Zhang H.-Q. 
Published: February 2011

Abstract
Entrainment fraction is one of the key parameters in many applications including wellbore and flow line design, separator design, wellbore loading, corrosion inhibition, etc. This study provides the first comprehensive entrainment data and their critical analysis for a full range of inclination angles ranging from horizontal to vertical in 76.2-mm internal diameter (ID) pipes. Experiments were conducted to investigate the effect of pipe inclination on entrainment fraction in air-water annular flow with inclination angles of 0°, 10°, 20°, 45°, 60°, 75°, and 90° from horizontal. Two techniques were utilized to measure the entrainment fraction: film removal and isokinetic sampling. The experimental results were compared with existing models and correlations, and the best predicting methods were determined for all flow orientations.
An inclination effect on entrainment fraction was observed. This effect occurred at low superficial gas velocities and was more prominent for higher superficial liquid velocities. Using the present study data, the Paleev and Filippovich (1966) correlation was found to be the most accurate in predicting entrainment fraction. Based on all available data, the Pan and Hanratty (2002b) correlation performed the best in predicting entrainment fraction in all pipe orientations. For vertical annular flow, the Oliemans et al. (1986) correlation predicted entrainment fraction more accurately. The Pan and Hanratty (2002b) correlation was most accurate in predicting entrainment fraction for horizontal annular flow. The Wallis (1969) correlation and the mechanistic model developed by Mantilla (2008) most accurately predicted the entrainment fraction for inclined annular flow.
Approach to Selection of the Optimal Lift Technique in the Vankor Field
Authors: Khasanov M. M. , Khabibullin R. A. , Pashali A. A. , Semenov A. A. 
Published: February 2011

Abstract
Artificial lift selection is one of the key decisions to make while starting production of new oil field. Widely used approaches include application range matrixes, decision trees, expert systems based on fuzzy logic. One of disadvantages of all these approaches is a disability to select the most appropriate lift technique; they usually screen out inapplicable techniques and suggest a variety of equally possible solutions. The main purpose of this study was to develop a new approach that will allow selecting optimal lift method based on economical criteria. An approach was tested on Vankor field.
The main idea was to compare different artificial lift techniques applied to the same well using NPV criteria. NPV was calculated as a function of well parameters, fluid properties and AL techniques limitations. Rod Pump, ESP, Gas Lift, PCP as well as natural flowing wells are considered. An application called Technologies Application Pattern (TAP) was developed. Well and fluid parameters as long as economical parameters are used as TAP input; the outputs are optimal flowing bottomhole pressure, oil rate and NPV for each technology considered.
Each of two production layers of the Vankor field has an aquifer and a gas cap. Natural energy is not enough for ensuring target field production profile and gas and water breakthroughs are main challenges for field development. Horizontal wells with high rates were selected for filed development plan. Based on this decision some of AL techniques were considered inappropriate (rod pump and PCP).
The paper discusses main AL selection steps for Vankor oil field. First we consider possible flow rates estimation for each lift technique as functions of GOR, watercut, and productivity index. Based on NPV estimation selection optimal AL is discussed. The final step includes sensitivity and risk analyses. It shows that the solution is more sensible to well depth and GOR. The Monte-Carlo method was used to the risk analysis.
Main results of this work are presented in the form of Technologies Application Map – a two-dimension projection of TAP calculation results. Well parameters are set on the axes of the map. Maximum (optimum) NPV for each lift technique is put on the map. Influence of significant parameters (like oil price) uncertainty AL selection is shown.
Restricted Diffusion Effects in Saturation Estimates from 2D Diffusion-Relaxation NMR Maps
Authors: Zielinski Lukasz , Ramamoorthy Raghu , Minh Chanh Cao , Al Daghar Khadija Ahmed , Sayed Raza Hassan , Abdelaal Atef Farouk 
Published: February 2011

Abstract
A new model is proposed for interpreting two-dimensional diffusion-relaxation nuclear magnetic resonance (2D NMR) maps by including the effects of restriction on the diffusion of water in a connected porous medium. The model's theoretical underpinnings are reviewed and a correlation derived between the diffusion and relaxation of restricted water molecules, i.e., the expected ‘water line’ where the water signal should appear on 2D NMR maps. The main application discussed in this paper is to improve the quantitative separation of different fluids in the formation, leading to better prediction of water and hydrocarbon saturations. In many carbonate formations, the effects of restriction may be quite pronounced making the standard fluid characterization with diffusion-relaxation maps questionable. The restricted-diffusion model is applied to laboratory measurements on carbonate core plugs and to an example log from a Middle East carbonate well where the saturations obtained with the new model are compared against other measures of saturation available in the dataset.
Cost Effective Field Applications Utilizing Coiled Tubing Inflatable Packer System in South Mexico
Authors: Robles Francisco Cazares , De La Fuente Rodriguez Juan Jose , Moreno Angel R. , Noguez Lugo Mario , Tellez Guadalupe , Avilés Rodrigo , Cesin Scarlet , Lian Eric 
Published: February 2011

Abstract
With the discovery of new fields becoming less common and the need to maximize economic recovery in mature fields, operators are trending towards rig-less intervention work to reduce cost and delays to production related to traditional workover rig interventions. With its field complexities, from low bottom hole pressure (BHP) to high temperature/high pressure (HT/HP) reservoirs, and from consolidated sandstone to naturally highly fractured carbonates, and large producing intervals in various flow units with active aquifers, southern Mexico poses a highly significant challenge for rig-less intervention in water control and zonal isolation to assure placement and accuracy of treatment fluids.
This paper discusses the implementations and results of two case histories in which a cost-effective application involving coiled tubing and inflatable packer systems were used for water control in a high water cut producing well and for well abandonment of a newly completed well. The utilization of coiled tubing combined with the inflatable packer is able to precisely deliver the treatment fluids to the zone of interest while the production tubing remains in place, which enhances timely and cost effective intervention solutions1 when compared to workover rig operations.
Case 1 presents the water control application using a coiled tubing inflatable packer system in combination with an organic crosslinked polymer gel, and micro-fine cement slurry for a naturally fractured carbonate reservoir in southern Mexico.
The result of this innovative rig-less approach exceeded the operator's expectations. The case history well was producing 815 BOPD and 5.2 MMSCFD with a water cut of 77%. After the water control treatment with the coiled tubing inflatable packer system, organic crosslinked polymer gel and micro-fine cement slurry, the well was producing 1,459 BOPD and 5.15 MMSCFD with a water cut of 0%.
Case 2 demonstrates a newly completed well with production tubing and packer already set and the well producing with high water cut from an open-hole completion. By using the inflatable packer system through coiled tubing and squeezing cement slurry to abandon the open-hole, a new interval could be perforated and exploited in just 28 hours; in contrast, conventional abandonment with a rig can take up to 10 days.
Optimum Parameterization for Saturation Modeling in Heterogeneous Hydrocarbon Reservoirs Using Well Log Inversion
Authors: Friedel Torsten , Moreno Jaime , Carrillat Alexis , Carnegie Andrew 
Published: February 2011

Abstract
Static or dynamic modeling of hydrocarbon reservoirs requires accurate modeling of the initial water saturation, which is normally a function of local rock quality and the presence of capillary forces. Without understanding how the latter two parameters impact the initial saturation distribution, both initial volumetric estimates and subsequent predictions are potentially meaningless. In the past, well-centric saturation-height modeling was the preferred technique for deriving the saturation model, which was based on regression of selected representative logs or capillary pressure experiments. In brownfields with potentially large numbers of suitable wells, this single-well technique does not leverage on the abundance of available data, which for the purposes of reservoir modeling is also on a more representative scale than core data and potentially covers larger reservoir portions, both aerially and vertically. The idea behind this new approach is to use a full-scale inversion technique integrating all suitable well and core data in a process similar to history matching. Initially, a physical model is developed that describes the saturation anywhere in the reservoir while taking into account different rock types and reservoir regions. With an initial set of parameters based on core observations, the process starts with a sensitivity analysis using Monte Carlo simulation. Insensitive parameters are tied to core data at this stage and the well log inversion procedure commences. For this procedure, an objective function describes the mismatch between the simulated and observed saturation. The model calibration, which is fully automatic using nonlinear solvers, will lead to the set of parameters that best fits core and log-observed saturations. The resulting parametric saturation model can be populated in 3D geocellular models and spatially analyzed in terms of mismatch and uncertainties. A comprehensive statistical analysis of the results helps to understand the role of the individual physical processes such as capillary pressure, as well as to define confidence intervals and cross-correlation between parameters. An example of a large carbonate reservoir with about 100 wells illustrates that the novel saturation modeling approach can contribute to significantly improved reservoir characterization.
In-Situ Heavy-Oil Fluid Density and Viscosity Determination Using Wireline Formation Testers in Carbonates Drilled With Water-Based Mud
Authors: Akkurt Ridvan , Seifert Douglas , Neumann Peter , Zeybek Murat , Ayyad Hazim 
Published: February 2011

Abstract
In-situ heavy oil density and viscosity can vary laterally and vertically in carbonate reservoirs. The spatial distribution of these PVT properties must be determined accurately for reserve assessment, reservoir simulation, well placement and other field development processes.
Although laboratory PVT analysis is the industry-standard source for fluid properties, the extensive time required to restore and process heavy oil fluid samples often minimizes the impact of such information during the drilling phase. The use of wireline formation testers, capable of measuring in-situ density and viscosity, can greatly aid the decision-making process providing timely basic PVT data, in addition to guiding the fluid sampling program and increasing the quality of the samples to be taken.
While in-situ measurement of fluid density and viscosity in oil-based-mud is well-established, accurate determination of such properties can be quite challenging in water-based-mud environments; especially in those cases of water-dominated flow, strongly emulsified fluids or high fraction of sediments in the flow line. Several techniques, such as sampling point optimization, pressure and flow rate control during pump-out, and tool-string configuration can minimize the adverse effects, thereby improving measurement and sampling quality. Yet, there can still be cases where the measurement accuracy can be limited due to the specific combination of fluid and formation properties, and borehole conditions.
In this paper, several case histories in a variety of borehole and mud conditions, including highly deviated and ultra-reach extended horizontal wells, are presented with comparisons to laboratory data when available. Results indicate that accurate in-situ density and viscosity determination is possible when sufficient amount of oil is present in the flow line. Experience also shows that measurement quality can be affected in suboptimal conditions involving strong emulsions, or range of viscosities outside the sensor specifications.
Development of Marcellus Shale in Pennsylvania
Authors: Belvalkar R. , Oyewole S. 
Published: February 2011

Abstract
A review of technologies and practices used for exploration and production of natural gas from the Marcellus Shale in Pennsylvania is given while shedding light on the entire process of natural gas production in the Marcellus Shale region of Pennsylvania. Entailing drilling and completions operations, production operations and transportation of natural gas tied together with regulation and policy in Pennsylvania. Horizontal drilling technology is used in shale play development along with well stimulation which is also needed to produce economically from these wells. This is achieved through hydraulic fracturing. Water is predominantly used for this but the use of other fluids is also being explored. For the transport of natural gas a network is present in Pennsylvania but gathering stations and other infrastructure needs to be setup. This is not easy in Pennsylvania due to the hilly nature of the region. Most common practices are developed locally as is the case in the Marcellus, with local operators and not the big majors heading the development of the Shale play but even they used techniques applied in the Barnett Shale to great success in the Marcellus Shale which goes to prove that a lot can be gained from other similar plays. The history of this region in producing natural gas is more than a hundred years old and so a lot has done in this region with regards to experimentation and technology additions in producing natural gas. Apart from producing and transportation of natural gas, another important aspect is regulation and policy which is strict when it comes to Pennsylvania. Along with this it would be beneficial for companies to develop good relations with residents in the area as these wells typically produce for long periods of time. Typical land restoration projects are now mandatory which all adds upto a higher overall cost of energy. To summarize all the factors needed to produce natural gas in this region economically and safely with leaving as small as a footprint as possible is explored.
Effectiveness of Water Jet Fracturing on a Horizontal Open Hole Completion: Case Study
Authors: Rosales Sigifredo J. , Hernández Rafael A. , Lynch Cynthia Yuen , Bustamante Ernesto 
Published: February 2011

Abstract
To date, the art of effective openhole, horizontal well fracturing is not well defined. Difficulties in regional sealing hamper the fracturing task and results can be suspect. Without proper isolation methods, the use of openhole, horizontal well fracturing is limited. During many fracturing processes, fracture or acid placement often occurs where fluid first contacts the borehole, often at the heel of the well.
A new method is now available that combines hydra-jetting and fracturing techniques. By using this new method, operators can position a jetting tool at the exact point where the fracture is required, without using sealing elements. Unlike other techniques, this new method allows operators to place multiple fractures in the same well; these fractures can be spaced evenly or unevenly as prescribed by the fracture-design program. Large-sized fractures can be placed with this method as well.
This technique was applied in a low-permeability environment in a horizontal, openhole completion. Treatment design proved simple, but unique to the job, to which success is attributed. In addition to tailoring a design for such treatment, reservoirmonitoring methods were applied to help measure the effectiveness of the overall stimulation program. Surface tiltmeter technology was used to map the hydraulic fractures. Mapping results indicated that induced fractures were placed in the area of interest, a well-documented difficult task on an openhole completion.
This paper discusses the basic principles of horizontal hydrajet fracturing on an openhole completion, observes the operational advantages of the technique, and highlights the significance of matching the right application to the right environment for treatment success.
Reservoir Modeling of CO2 Plume Behavior Calibrated Against Monitoring Data From Sleipner, Norway
Authors: Singh Varunendra , Cavanagh Andrew , Hansen Hilde , Nazarian Bamshad , Iding Martin , Ringrose Philip 
Published: February 2011

Abstract
Sleipner is a commercial CO2 storage site in the North Sea with good constraints from monitoring data, but also with some significant uncertainties regarding temperature, pressure and gas/brine behavior. At Sleipner, we have used high-quality repeated seismic and gravimetric surveys for monitoring and calibrating the reservoir uncertainties. To model the CO2 behavior we have used two main approaches: a) traditional reservoir simulations, using black oil and compositional fluid descriptions; and b) invasion percolation simulations, using threshold pressure and fluid density descriptions that assume the dominance of capillary and gravity forces. The key findings from the study are:
The invasion percolation simulation gave the best initial match to observed data, leading us to reassess the input assumptions for the black oil and compositional simulations. By taking into account gravity segregation and modifying the reservoir simulation input data, we were able to get a much better match for the black oil and compositional simulations. There is still scope for further optimization and history matching, however, this study has reduced the range of domain variables leading to an improved understanding of the flow processes involved in geological storage of CO2 in saline formations.
The study has led us to conclude that we can make realistic and predictive CO2 storage models provided that the site-specific conditions are honored, including reservoir and fluid property characterization. The necessary tight constraints on input parameters are achieved by calibration against monitoring data.
Our study illustrates both a rather novel approach to modeling CO2 storage and the need for improved input to conventional simulators. Application of our approach to other CO2 storage sites will help in achieving more realistic understanding of CO2 storage, thereby contributing to the maturation of CO2 storage technology worldwide.