bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of CO2 in Heavy-Oil Waterflooding
Authors: Nasehi M.. , Asghari K.. 
Published: February 2011

Abstract
Waterflooding has been used in oil recovery for many years and is an important technique in conventional oil recovery. In the case of viscous heavy oils, due to the low mobility of heavy oil and high mobility ratio between the displacing fluid (water) and the displaced fluid (heavy oil), reported recoveries have been very low and have been associated with very high volumes of produced water.
Use of CO2 in heavy oil waterflooding, as a solvent that might effectively reduce the viscosity of heavy oil and causes it to swell, is the focus of this study.
This paper presents the results of eleven core-flooding experiments designed to study the effect of CO2 utilization in waterflooding of heavy oils. Injection strategies used in these experiments involved different combinations of CO2 and brine, including intermittent injection of separate slugs as well as injecting carbonated water. In reported experiments, following the completion of waterflooding tests, CO2 slugs of 10% and 25% pore volumes, or carbonated water was injected into the cores followed by a shut-in period. Water injection was resumed at the end of shut-in period, and any additional oil produced was collected. Heavy oil samples with viscosities of 1000 to 2000 cp were used and experiments were carried out at pressures of 500 and 1000 psi (3.45 and 6.9 MPa), temperature of 30°C, and water injection rates between 1 and 50 feet per day. Carbonated water used in these experiments was prepared by dissolving CO2 in brine (1% wt. NaCl) at 820 psi over 4 days.
Results of this study indicate that the use of CO2 significantly improves recovery of heavy oil by waterflooding. Incremental recoveries in the range of 5 to 27.5% OOIP were achieved by CO2 in combination with waterflooding. It was also found that the increase in the operating pressure results in increased oil recovery. Furthermore, the injection of larger CO2 volume increased the oil recovery. It was also found that during the post CO2 waterflooding, greater recovery improvements are achieved from lower permeability systems. Comparison between the lower and the higher viscosity oils also showed that the use of CO2 results in greater recovery improvements for the higher viscosity oil system.
Numerical Simulation and Modeling of Enhanced Gas Recovery and CO2 Sequestration in Shale Gas Reservoirs: A Feasibility Study
Authors: Kalantari-Dahaghi A.. 
Published: February 2011

Abstract
The process of modeling ultra low permeability and desorption-controlled shale gas reservoirs has always been challenging. Desorption is an important issue in recovery of many shale plays. Although a large amount of gas in place comes from adsorbed gas, ultra tight matrix and high bottom hole pressure may not allow this gas be produced.
In this paper, an integrated workflow is described, which demonstrates a quantitative platform for shale gas production optimization through capturing the essential characteristics of shale gas reservoirs. Because organic matter has a greater sorption affinity for CO2 than methane, a comprehensive feasibility study has been performed to evaluate the applicability and significance of CO2 injection (with simultaneous production of methane) on expedition of desorption process and also CO2 sequestration in shale.
Modeling of complex fracture networks is a very important step in simulation of shale reservoirs. Discrete fracture network (DFN) models can be used to generate and validate multiple realizations for a quantitative measure of uncertainty. A 3-D discrete fracture network using typical shale properties was generated stochastically, based on different realizations (homogenous and heterogeneous fracture properties). The complex DFNs were upscaled in order to simulate fluid flow through the system. In addition, hydraulic fractures were introduced to the model. Sensitivity analysis has been performed on key matrix and fracture properties for both natural and hydraulic fractures.
Numerical simulation was performed using appropriate gridding (logarithmic local grid refinement around the hydraulic fractures) and, in order to capture long transient gas flow from matrix to fracture, multi porosity model with matrix sub grids has been employed. This step was followed by a history matching process and the fracture and reservoir properties were varied within a range that appears consistent with actual typical shale gas well performance. One model, which gave a better approximation of the actual production profile, was selected for CO2 injection study.
In order to understand the economic effect of matrix swelling on permeability and injectivity in the presence of CO2, different injection strategies (patterns, injection time interval and rate) were defined in order to recommend the best scenario for maximum and economic recovery.
Predicting the Migration of CO2 Plume Using Injection Data and a Distance-Metric Approach to Reservoir-Model Selection
Authors: Bhowmik S.. , Srinivasan S.. , Bryant S. L. 
Published: February 2011

AbstractDuring the operation of a geological carbon storage project, verifying that the CO2 plume remains within the permitted zone will be of particular interest both to regulators and to operators. We demonstrate a model selection algorithm that refines an initial suite of subsurface models representing the prior uncertainty to create a posterior set of subsurface models that reflect injection performance consistent with that observed. Such posterior models can be used to represent uncertainty in the future migration of the CO2 plume. Because only injection data is required, the method provides a very inexpensive method to map the migration of the plume and the associated uncertainty in migration paths. We illustrate the method using a field data set.
Impurities in CO2 - Rich Mixtures Impact CO2 Pipeline Design: Implications for Calculating CO2 Transport Capacity
Authors: Jung W.. , Nicot J. -P. 
Published: February 2011

Abstract
Existing carbon dioxide (CO2) pipelines commonly contain over 90% of CO2 mixed with major impurities such as methane (CH4), hydrogen sulfide (H2S), and nitrogen (N2). Other minor impurities are carbon monoxide (CO), oxygen (O2), C2+ hydrocarbons, and H2O. CO2 is transported in the gas phase, liquid phase, or as a supercritical fluid. Phase behaviors of CO2 mixtures are based on the Vapor Liquid Equilibrium (VLE) and critical points of mixtures. The predictions of VLE are essential to the design and operation of CO2 mixture pipelines. The VLE and critical points for binary or ternary CO2 mixtures are predicted by Equations of State (EOS). This study illustrates how major impurities impact transport capacities of CO2-rich mixture pipelines. The calculations indicate that the flow capacity in the liquid phase is approximately twice as high as in the gas phase.
Perspectives on CCS Cost and Economics
Authors: Kheshgi H. S. , Bhore N. A. , Hirsch R. B. , Parker M. E. , Teletzke G. F. , Thomann H.. 
Published: February 2011

Abstract
Focus on Carbon Capture and Storage (CCS) has grown over the past decade with recognition of CCS’s potential to make deep CO2 emission reductions and that fossil fuels will continue to be needed to supply much of the world's energy demands for decades to come. How CCS will compare to other options in the future depends critically on the cost of CCS (the focus of this paper) and resolution of barriers to CCS deployment, as well as costs and barriers for other emission reduction options.
This paper provides a comparison of the cost of electricity of five power generation options – coal and gas Combined Cycle Gas Turbine (CCGT,) with and without CCS and nuclear – and shows regions of carbon price and fuel prices where each can be economically viable.
Current cost estimates for coal CCS for Nth-of-a-kind power generation plant are in the 60-100 $/ton of CO2 avoided – higher than some of the earlier CCS estimates, and higher than the generally accepted range of expected carbon prices in the next two decades. The high cost of coal CCS suggests that:Gas based power generation is much more economical than coal CCS at carbon prices below 60-100 $/ton CO2.Even after carbon prices reach 60-100 $/ton CO2, gas CCS produces lower cost electricity than coal CCS as long as natural gas prices remain below 9 $/MBTU.Nuclear has a lower cost of electricity than coal CCS.
Although Coal or Gas CCS is unlikely to be economical in power generation over the next two decades, subsidized demonstrations of CCS are likely to occur. In addition, components of CCS technologies will continue to be economically practiced in early use segments such as natural gas processing and Enhanced Oil Recovery (EOR) operations. In this paper, we share ExxonMobil’s experience at LaBarge in using CO2 from a natural gas facility for EOR use – the single largest CO2 capture site for sub-surface injection in the world today. In the natural gas processing industry, CO2 separation cost is a fraction of the cost of CO2 capture in power generation due to its higher gas pressure, and the CO2 separation is typically necessary to monetize the natural gas resource.
In contrast, CCS for most refinery and industrial emissions is expected to be significantly more costly than power generation because the CO2 streams are typically smaller scale and more distributed than those from large power plants.
Realistic estimates of cost for CCS, as well as for other greenhouse gas (GHG) mitigation options, are an important input for focusing research, development and demonstration (RD&D) addressing barriers to applications that show the greatest promise, and development of sound policy.
Storing CO2 With Next Generation CO2-EOR Technology
Authors: Ferguson R. C. , Kuuskraa V. A. , Van Leeuwen T. S. , Remson D.. 
Published: February 2011

Abstract
CO2 enhanced oil recovery (CO2-EOR) offers the potential for storing significant volumes of carbon dioxide emissions while increasing domestic oil production. This paper, based on a recently updated report for DOE/NETL, examines the effect that "Next Generation" technologies will have on the CO2 storage and oil production potential of CO2-EOR. The paper examines the causes of sub-optimal CO2 storage and oil recovery efficiencies by current CO2-EOR practices and how a group of advanced or "Next-Generation" CO2-EOR technology could increase both CO2 storage volumes and oil recovery. Technologies investigated include: using increased volumes of injected and permanently sequestered CO2, optimizing well placement and pattern alignment, and using reservoir miscibility and viscosity enhancers.
Influence of Thermo-Elastic Stress on CO2 Injection Induced Fractures During Storage
Authors: Luo Zhiyuan , Bryant Steven L. 
Published: February 2011

AbstractCommercial CO2 geologic storage will require large injection rates and will favor pipeline transport of CO2 as a dense (liquid) phase. Thus the temperature of CO2 entering a storage formation may be significantly lower than the formation temperature. This difference in temperature introduces a thermo-elastic stress that reduces the critical pressure required for initiation of fractures. The initiation of fractures poses a potentially serious risk for CO2 leakage to upper formations or surface.We present a simple model to predict the range of bottomhole fluid temperatures, and thus the range of thermo-elastic stresses, for different operating conditions. The operators and regulators can estimate the safe injection rate range based on the model to avoid injection-induced fracture initiation around an injection well. Different injection strategies are considered in this work. The effect of Joule-Thomson cooling across the perforations is investigated and found to be small. We also evaluate the sensitivity of safe injection rate to formation permeability, heat transfer coefficient, geothermal gradient, and surface temperatures of injection fluid and well. Results from this study provide a guide for risk assessment and form a basis for investigating the extension of initiated fractures.
Specialties of Energy Conservation and Application of Control Systems in a Large Cooling Water Project
Authors: Relwani Harendra , Sarma Anupindi , Salamat Reza 
Published: February 2011

Abstract
Having a battery of parallel operating pumps with variable speed drive system (VSDS) saves a great deal of energy especially for big pumps with large throughputs. Back in 80s and even 90s, however, relying on variable speed drive pumps with high target reliability and 100% availability was a big task mainly due to the complexities of the associated power electronics and the control issues. In the present era, sophisticated control equipment and philosophy allows taking the full advantage of VSDS pumping system whereby the pump generates a dynamic head only as much as plant requires. As a result the operator ends up in saving substantial operating expenditure in terms of energy bills and simultaneously reduces the environmental impact due to reduction in CO2 emission associated with the power generation. The larger the plants, the larger the consequent savings thus demanding due design attention at early stages.
The proceeding paper discusses the salient design and operational aspects of a large cooling sea water project in Ras Laffan, one of the largest industrial sites in the world, situated 80 km North of Doha in the state of Qatar. This project is unique in terms of its seawater throughput of nearly 1 Million m3/hr by variable speed drive pumps, through a set of very large diameter GRP pipelines to various end users spread throughout the industrial city, with varying seawater demand. These series of 27 pumps each around 7.5 MW with a future provision of additional 6 pumps are located in three separate pump houses. The project also boasts one of the largest electro chlorination plants in the world. The paper describes in sufficient detail the energy saving aspects of a large VSDS driven cooling water system and the associated reliable control with no allowable downtime that will jeopardize the water supply to any end user at any point of time. The design target reliability and availability are 99.7% and 100% respectively. The potential opportunities of pump head savings are identified and the associated benefits in power and CO2 emission are evaluated by comparing the various operational scenarios. The paper also describes the specialties and application of the control systems.
In the proceeding work it is found that on the current project alone, more than 400 GWhr of energy per annum can be saved by the application of VSDS system translating into a reduction in emission of nearly 170,000 tones of CO2 on annual basis. An efficient and robust control strategy has resulted in less operating costs in terms of energy bills and retarding the pollution of the environment.
With the use of cooling water plants around the world inevitably on the rise as more oil & gas facilities of mega size are being built, it is concluded that all viable power saving options should be explored at the early concept stages. Sufficient emphasis should be placed on energy optimization and the resultant environmental benefits.
Reservoir Modeling to Characterize Dual Porosity, Tengiz Field, Republic Of Kazakhstan
Authors: Tankersley T.. , Narr W.. , King G.. , Camerlo R.. , Zhumagulova A.. , Skalinski M.. , Pan Y.. 
Published: February 2011

AbstractTengiz Field is the world's deepest developed supergiant oil field, with an oil column of nearly 1600m. The reservoir consists of Devonian and Carboniferous platform/slope carbonates, divided into three stratigraphically-defined units. Production of over 500,000 BOPD is mainly from the upper unit. A significant portion of this production is controlled by natural fractures. A new reservoir model has been constructed to support a future growth project, including miscible gas injection, and to guide reservoir management strategies, development planning, and oil-in-place estimation.Our new model represents a significant change from previous models in that a dual porosity, dual permeability flow formulation (fracture and matrix) is being applied. This change to dual porosity, which is necessary to effectively characterize the fracture-matrix flow, requires a significant modification of the overall reservoir modeling workflow. Matrix porosity and permeability are distributed into the fine-scale model and fracture properties are populated into the model after upscaling, because representative fracture attributes are only available at a large scale.Fracture porosity is high in the depositional slope (about 0.4%) due to the cavernous character of portions of the fracture system. This fracture porosity represents a significant volume, and has a large impact on reserves. Fracture permeability is also a critical factor, and has a large affect on flow behavior and recovery. Although fractures are important, their intersection by wellbores is relatively rare, due mainly to under-sampling of sub-vertical fractures by vertical wells and sparse well control in the slope. Because of this under-sampling, and general ambiguity in image-log data, uncertainty associated with fracture properties is large. To address this uncertainty, significant effort has gone into collecting reservoir surveillance data. In addition, fracture properties from image logs were reconciled with well tests and other logs.
Tengiz Field (Republic of Kazakhstan) Unit 1 Platform Static Model: Using a Hybrid Depositional – Diagenetic Approach
Authors: Kenter Jeroen A. , Tankersley Terrell , Skalinski Mark , Harris Paul (Mitch) , Levy Marge , Dickson Tony , Jacob Gary 
Published: February 2011

Abstract
Traditional rock typing combined with an inferred depositional linkage for variogram-based simulation is a standard approach in carbonates. In the Tengiz Unit 1 platform, reservoir properties of carbonates as defined by Petrophysical Rock Types (PRTs) are the product of primary depositional facies and diagenetic modification that have separate spatial trends and interactions. Careful, multidisciplinary and targeted analysis is required to unravel such trends from the usually complex hard data sets, but is critical as an understanding of the trends forms the basis for reservoir modeling of the Tengiz Unit 1 platform. Depositional cycles in the Unit 1 Tengiz platform (Late Visean to Bashkirian) are made up of a succession of generally shoaling lithofacies overlying a sharp base with evidence for subaerial exposure and/or flooding. Systematic study of the diagenetic products of several sequences across the platform using petrography, stable isotopes and CL revealed that the diagenetic modification includes early meteoric dissolution and subsequent cementation, late burial dissolution and late burial bitumen cementation. PRTs are designed to include spatial attributes of the combined stratigraphic, facies and diagenetic framework form the basis for the Multiple Point Statistics and Facies Distribution Modeling (MPS/FDM) simulation of the SIM08T Unit 1 static platform reservoir model. Of the six PRTs, one is linked to volcanic ash (PRT 1), one associated with bitumen (PRT 2) and four with increasing porosity (PRTs 3-6) where PRT 3 tight and PRTs 4-6 represent increasing reservoir quality with PRT 6 the highest quality. PRT maps and a vertical proportion curve were used to generate the facies probability cube and convolved with training images, specifying the spatial interrelationship, to generate a PRT realization. The revised sequence stratigraphic framework and integration of novel concepts in modeling the diagenetic overprint addressed the need for a refined understanding of the platform in preparation for the FGP miscible gas injection project. In addition, the extensive use of MPS/FDM modeling approaches in Unit 1 has resulted in a more realistic integration of both depositional and diagenetic trends in the Unit 1 platform.
Updated Rock Type Definition and Pore Type Classification of a Carbonate Buildup, Tengiz Field, Republic of Kazakhstan
Authors: Skalinski Mark , Kenter Jeroen , Jenkins Steve , Tankersley Terrell 
Published: February 2011

Abstract
Tengiz is an isolated Paleozoic carbonate build-up located in the Pricaspian Basin, Republic of Kazakhstan. The reservoir contains over 26 Billion Barrels OOIP and is one of the world’s deepest supergiant fields. The introduction of petrophysical rock types (PRT) and pore type classification has significantly improved oil in place estimation and reservoir characterization of this complex carbonate field.
The Tengiz platform is a cyclic alternation of grainstone and packstone with thin volcanic ash layers and later strongly modified by diagenesis. The Tengiz flank areas are dominated by microbial boundstone deposition in an upper slope environment and detrital sediment in the lower slope. Carbonate facies in the Tengiz flanks are generally tight with bitumen cement and are dissected by fracture systems which act as fluid conduits. The classification of pore types and development of algorithms to predict pore types are based on a data set of more than 550 mercury injection pressure measurements. The Tengiz pore classification is scale-driven and has a direct impact on permeability and flow performance. The character and distribution of pore geometries in Tengiz buildup is determined by a variety of depositional and diagenetic processes, including early differential cementation, mechanical compaction and failure, and phases of dissolution and calcite and bitumen cementation.
PRTs were developed to characterize various depositional and diagenetic regions of the Tengiz Field. Several distinct groupings of petrophysical rock types are recognized in the Tengiz platform and flank. These groupings include Volcanic Dominated, Bitumen Rich, Tight/Cemented, and reservoir facies of varying quality.
A set of SRT (Slope Rock Types) were developed to improve characterization of the Tengiz slope facies. The slope largely consists of tight, algal boundstone and breccia facies which have undergone extensive corrosive diagenesis. Permeability is significantly enhanced in the Tengiz slope through these diagenetic processes.
In 2008, a new reservoir model was constructed for Tengiz which implements the concepts of PRT and SRT to improve characterization of pore sizes and pore throats across the field. These distributions of pore size and pore throat geometry are a primary control on oil recovery in carbonate reservoirs. Improved characterization of pore geometry and key reservoir properties in the Tengiz Field has been achieved using petrophysical rock types. The introduction of PRT and SRT at Tengiz has contributed to improved estimates of volumes of oil in place and improved reservoir management.
Analogues as a Tool for Modeling Fields
Authors: Lapointe P. A. , Glass L. W. 
Published: February 2011

Abstract
Carbonate mounds are reported throughout the stratigraphic scale from the Proterozoic to the Present. They developed on continental margins or intra-platform environments, in water depths ranging 1000 to 10 m and represent targets for hydrocarbon exploration in Kazakhstan, leading to recent discoveries of giant hydrocarbon accumulations (e.g. Karachaganak, Grigor’yeva, 1992; O’Hearn et al, 2003). They generated renewed interest in these distinctive carbonate deposits. An understanding of recent carbonate mounds systems in particular those drilled by leg IODP 307, provides a tool to appraise ancient subsurface mound carbonates and as a complement classic outcrops studies.
The cyclic records observed in recent mounds are keys for understanding the reservoir compartmentalization within mound complexes. The comparative analysis of mound evolution – focusing on early to late diagenetic processes, products and patterns – in the recent and ancient deposits provides new insights into reservoir porosity and permeability.