bluuebunny/crossref_metadata_2025_split huggingface dataset:
Air Injection in Heavy Oil Reservoirs - A Process Whose Time Has Come (Again)
Authors: Ursenbach M.G. , Moore R.G. , Mehta S.A. 
Published: June 2014

Abstract
Air injection in heavy oil and bitumen reservoirs, also known as in-situ combustion or fireflooding, is an enhanced recovery process that has been around for several decades. While on paper or in the laboratory this oil recovery process shows tremendous potential, its success in past field applications has been spotty at best.
Times have changed, and so has our understanding of air injection-based oil recovery processes. Our available technologies for accessing and producing the reservoir and our emphasis on reducing environmental impacts have changed as well. In short, the industry is smarter, has better technology, and maintains a significant commitment to sustainable resource development.
This paper reviews portions of the past history of air injection in Canadian heavy oil and bitumen reservoirs; discusses the significant advances in our understanding of the in-situ process; reviews currently successful air-injection projects; summarizes the keys to successful implementation of air-injection-based recovery processes; and proposes several novel applications of air injection, including hybrid processes with steam or vapour solvent, in-situ upgrading, in-situ steam generation, and in-situ gasification.
Introduction
Since its accidental discovery in the early 1900s, the use of air injection as an enhanced oil recovery process has experienced a somewhat checkered history. In the 1950s and 1960s, it was actively and successfully advanced as a thermal process for heavy oils in California. Many of those projects have been summarized by Chu(1) and Sarathi(2). The successes in California brought in-situ combustion or fireflooding to Canadian heavy oils and bitumens in the 1960s to 1980s. While there were some successes in these pilots and projects, there were many more failures, and air injection in heavy oils never seemed to reach its theoretical potential.
In the two decades that have elapsed since then, significant research efforts have been made to understand both the causes of failures and successes in past in-situ combustion projects. At the same time, the heavy oil industry has evolved significantly.
Valuation of Swing Contracts by Least-Squares Monte Carlo Simulation
Authors: Willigers Bart J.A. , Begg Steve H. , Bratvold Reidar 
Published: June 2014

Summary
Natural gas and electricity are commonly traded through swing contracts that enable the buyer to exploit changes in market price or market demand by varying the quantity they receive from the producer (seller). The producer is assured of selling a minimum quantity at a fixed price, but must be able to meet the variable demand from the buyer. The flexibility of such contracts enables both parties to mitigate the risks and exploit the opportunities that arise from uncertainty in production, demand, price, and so on. But how valuable are they? Traditional net present value (NPV), based on expected values, cannot value this flexibility, and the traditional options/valuation techniques could not model the complexity of the terms of such contracts.
Taking gas contracts as an example, this paper seeks to (a) raise awareness of how flexibility creates value for both parties and (b) show how least-squares Monte Carlo (LSM) simulation can be used to quantify its value in dollar terms, from the perspective of both producer and buyer. Because the value of flexibility arises from the ability it gives to respond to fluctuations (e.g., in commodity prices), a useful model of swing contracts needs to reflect the nature of these fluctuations.
CO2-Storage Capacity—Combining Geology, Engineering and Economics
Authors: Allinson W.G.. G. , Cinar Y.. , Neal P.R.. R. , Kaldi J.. , Paterson L.. 
Published: June 2014

Summary
This paper argues that any carbon dioxide (CO2) capacity-estimation method requires a combination of geological, engineering, and economic analyses to provide rigorous capacity estimates. It also argues that the classification of capacity estimates should follow concepts in the existing SPE Petroleum Resource Management System (PRMS) (SPE 2007) as closely as possible. The paper takes the discussion of CO2-storage capacity significantly further. It also aligns storage-capacity definitions more closely to the widely accepted PRMS.
Numerous authors and organizations have proposed CO2-capacity classification and calculation systems. In most of them, there is a definition of CO2-storage capacity that is intended to parallel the definition of petroleum reserves—namely, the volume of hydrocarbons that can be commercially recovered from known accumulations from a given date. However, each of the proposed systems applies economics only at the highest classifications of their systems. This is attributed to the infancy of the carbon-capture-and-storage (CCS) industry and/or the lack of a carbon price. However, in this paper, we demonstrate how economics combined with analytical and numerical injectivity modeling on the basis of geological models of the subsurface can help determine practical storage capacity.
In doing this, the paper makes observations about methods for estimating storage capacity, shows results of reservoir simulations and economic analyses, draws on SPE and internationally accepted methodologies and definitions of petroleum resources, and discusses how equivalent definitions can be applied to storage capacity. Finally, the paper provides recommendations for an improved CO2-storage-capacity classification system.
Introduction of A New Well Design to The Narrabri Coal Seam Gas Project
Authors: Hedger Linda K. , Cunnington Mike 
Published: June 2014

Abstract
Reservoir studies indicated that horizontal wells drilled in seam and intersecting vertical production wells were the optimal design to produce coal seam gas from the Narrabri CSG Project. An aggressive campaign of production pilots was drilled in 2009 and early 2010 to prove the potential of three coal seams in the Project area. The pilot wells included two dual lateral horizontal wells, with each horizontal well intersecting three vertical wells; a tri-lateral horizontal well which intersected four vertical wells; two long and three short single lateral horizontal wells intersecting one vertical well each; and three short, single lateral horizontal wells drilled from a single drilling pad to intersect three vertical wells. The importance to the company of the results required a high degree of certainty in well construction success.
There was very little time for rig start up issues to be addressed before the first horizontal well was drilled and early development of a competent wellsite team was essential. With little precedent and many unknowns, a low risk, fully engineered approach to the well design and drilling operations was adopted.
Connection of the vertical and horizontal wellbores is critical, and intersection techniques have been developed and refined. The Rotating Magnet Ranging System was introduced to Australia for this project, and adoption of this technology has subtle implications for directional drilling equipment and techniques. The wellbore hydraulics design and management while drilling program differed in several respects to conventional horizontal drilling, and performed very well.
The selection of the rig package, down-hole equipment and personnel underpinned the success of the 2009 – 2010 drilling campaign, and is described. The technical standards developed by the operation will interest other coal seam gas operators who face the challenge of economic extraction of coal seam gas, particularly from anisotropically fractured or deeper, lower permeability coals.
Estimating CO2 Fluxes Along Leaky Wellbores
Authors: Tao Qing , Checkai Dean A. , Huerta Nicolas J. , Bryant Steven L. 
Published: June 2014

Summary
Large-scale geological storage of carbon dioxide (CO2) is likely to bring CO2 plumes into contact with a large number of existing wellbores. The flux of CO2 along a leaking wellbore requires a model of fluid properties and of transport along the leakage pathway. Knowing the range of effective permeability of faulty cement is essential for estimating the risk of CO2 leakage. The central premise of this paper is that the leakage pathway in wells that exhibit sustained casing pressure (SCP) is analogous to the rate-limiting part of the leakage pathway in any wellbore that CO2 might encounter. Thus, field observations of SCP can be used to estimate transport properties of a CO2-leakage pathway. Uncertainty in the estimate can be reduced by accounting for constraints from well-construction geometry and from physical considerations. We then describe a simple CO2-leakage model. The model accounts for variation in CO2 properties along the leakage path and allows the path to terminate in an unconfined (constant-pressure) exit. The latter assumption provides a worst-case leakage flux.
By use of pathway permeabilities consistent with observations in SCP wells, we obtain a range of CO2 fluxes for the cases of buoyancy-driven (post-injection) and pressure-driven (during injection) leakage. Assuming the frequency distribution is representative of SCP wells, we observe that in leakage pathways corresponding to the slow but nonnegligible buildup of casing pressure (several psi/D), the effective permeability of the leakage path is in the range of microdarcies to hundreds of microdarcies, and the corresponding CO2 fluxes are comparable with naturally occurring background fluxes observed at the ground surface. In pathways corresponding to intermediate and fast buildup rate of casing pressure (tens to hundreds of psi/D), the effective permeability is in the range of tenths to tens of millidarcies, and the CO2 fluxes are comparable with surface flux measurements at the Illinois basin and at the natural seep at Crystal Geyser (Utah). In pathways corresponding to very fast buildup rate (thousands of psi/D), the effective permeability is from tens to hundreds of millidarcies and the CO2 fluxes are up to three orders of magnitude higher than those measured at Crystal Geyser.
Effect of Oil-Viscosity-Gradient Presence on SAGD
Authors: Chen Joyce , Ito Yoshiaki 
Published: June 2014

Summary
The presence of an oil-viscosity gradient appears to be a real phenomenon in the field, and its influence on the steam-assisted-gravity-drainage (SAGD) process has been studied by various researchers. However, there is potential to refine previous results to exploit the impact of viscosity gradients on SAGD-oil-recovery-process performance. This paper covers our simulation study of the impact of an oil-viscosity-gradient presence on SAGD operation. Various SAGD operating scenarios in the reservoir with the presence of a vertical oil-viscosity gradient were investigated and simulated. The conclusions are summarized as follows:
The presence of a vertical oil-viscosity gradient in the reservoir had a mild effect on the SAGD-oil-recovery rate, while the effect on the oil-recovery factor was insignificant.
J-Well SAGD, in which a J-well replaces the horizontal producer in a standard SAGD-well configuration, did not perform as well as SAGD with a standard well configuration (two parallel horizontal wells). These two conclusions are not in agreement with previous findings by other research groups.
Observations from some SAGD field tests indicate that the steam chamber could fail to reach the top of reservoirs. For those cases, gas injection could potentially help to recover the oil from the layer above the steam chamber. If that is true, the presence of an oil-viscosity gradient might have some impact on SAGD performance with gas injection.
Because local steam-trap control is required for J-Well SAGD (JAGASS) operation to optimize performance, the challenge and feasibility of local steam-trap control are also discussed in this paper. Some of the SAGD field evidence will be provided to support our simulation results.
Drilling a Better Pair: New Technologies in SAGD Directional Drilling
Authors: Zimmer Chad , Richter Dean , Person John , Tilley Jim , Bittar Michael 
Published: June 2014

Summary
The precise placement of well pairs is one of the most-crucial factors in the successful execution of a steam-assisted-gravity-drainage (SAGD) drilling program. A SAGD drilling program includes placing the producer well relative to the reservoir boundaries and twinning the producer with the injector well accurately. Delivering on these high expectations in unconsolidated formations (e.g., the McMurray oil sands in Canada) requires a strong focus on technological innovation.
A common practice in drilling SAGD wells in northeast Alberta is to drill lateral SAGD pairs with conventional, steerable mud motors and logging-while-drilling (LWD) resistivity measurements. Although this combination has delivered success, certain limitations exist in terms of wellbore quality and placement. At a demonstration project by a major oil company, several industry firsts were implemented successfully, including a combination of the newest and most-cutting-edge directional, measurement, and LWD technology.
The keystone of these industry firsts was the application of a soft-formation-modified, point-the-bit rotary-steerable system (RSS) used on 20 horizontal wells. Combined with an ultradeep azimuthal resistivity sensor, the RSS provided precise geosteering along the bottombed boundary in the producer wells, resulting in improved reservoir capture and characterization. More on-bottom time enabled more-efficient drilling and reduced well costs significantly. Highly smooth liner runs reflected the lack of tortuosity in the wellbore, made possible by the rotary bottomhole assembly (BHA). Improved directional control made uniform well separation possible between lateral pairs, thereby reducing the risk of hot spots and short circuiting during SAGD operations. The use of an even-walled power section above the RSS increased the bit rev/min for improved BHA responsiveness while minimizing casing and pipe wear. Overall, the results and lessons learned from the demonstration of these new techniques provide a clear indication of the progressive future of directional drilling in SAGD.
A Fully-Coupled Geomechanics and Flow Model for Hydraulic Fracturing and Reservoir Engineering Applications
Authors: Charoenwongsa S. , Kazemi H. , Miskimins J. , Fakcharoenphol P. 
Published: June 2014

Abstract
In this paper we present a practical fully-coupled geomechanics and flow model for application to hydraulic fracturing, especially in tight gas reservoirs, and other reservoir engineering applications. The mathematical formulation is consistent with conventional finite-difference reservoir simulation code to include any number of phases, components and even thermal problems. In addition, the propagation of strain displacement front as a wave, and the relevant changes in stress with time, can be tracked through the wave component of the geomechanics equations. We show the development of an efficient finite-difference computer code for rock deformation including thermal and wave propagation effects. The numerical approach chosen uses two different control volumes—one for fluid and heat flow and another one for rock deformation.
The ultimate goal is to provide a tool to assess the effect of pore pressure, cooling or heating the reservoir, and propagation of a strain wave resulting from hydraulic fracturing on the reservoir rock frame. This information is crucial for determining the effect of shear stress on opening or closing of natural fractures during creation of hydraulic fractures, and changes in shear- and compressional- wave velocities for seismic imaging purposes. A specific application of the product of this research is to simulate fracture propagation, gel cleanup and water block issues in hydraulic fracturing.
The modeling results indicate significant change in shear stresses near hydraulic fractures as a result of hydraulic fracture face displacement perpendicular to the fracture face and not as much from pore pressure change because the filtrate does not travel very far into the reservoir. Similarly, temperature change effects are also very significant in changing stress distribution.
Technology Options and Integration Concepts for Implementing CO2 Capture in Oil-Sands Operations
Authors: Ordorica-Garcia Guillermo , Nikoo Mehrdokt , Carbo Michiel , Bolea Irene 
Published: June 2014

Summary
The majority of the technology development for CO2 capture and storage (CCS) is driven by the electric-utility industry, in which the emphasis is on large centralized units for electric-power generation with coal as the primary fuel. The implementation of CCS in oil-sands operations has significant potential to provide meaningful carbon-emissions reductions. This paper presents various concepts for integrating leading CO2-capture techniques to bitumen-extraction and -upgrading processes. The main carbon-capture technologies are reviewed, and their relative advantages and disadvantages for implementation in bitumen mining, thermal bitumen extraction, and bitumen upgrading are discussed, leading to a qualitative assessment of their suitability for each oil-sands process.
Unique CO2-Injection Experience in the Bati Raman Field May Lead to a Proposal of EOR/Sequestration CO2 Network in the Middle East
Authors: Sahin S.. , Kalfa U.. , Celebioglu D.. 
Published: June 2014

Summary
Carbon capture and storage (CCS) is one of the most important emission-reduction technologies available for large stationary CO2 sources. Fossil-fueled power generation is the largest source of carbon dioxide (CO2) that could be captured and stored. Depleted oil and gas fields and major CO2 sources nearby are ideal places for large-scale geological storage. Injection of CO2 into a depleted reservoir can enhance the recovery of hydrocarbons. The circumstances, in fact, dictate that the CO2 enhanced-oil-recovery (EOR) industry and power-generation sector should be eager to magnify the mutually beneficial link between CO2 EOR and new industrial sources of CO2.
In 1986, the Turkish Petroleum Corporation (TPAO) started the first large-scale immiscible-CO2-injection project in southeastern Turkey. Approximately 1 million tons/yr of naturally occurring CO2 has been injected into Garzan carbonates in the Bati Raman field. A substantial increase in the production rate and ultimate recovery has been experienced, and this is expected to continue. The Bati Raman immiscible-CO2-injection project has been acknowledged as one of the most unique and successful EOR applications in the history of heavy oil in fractured-limestone reservoirs.
There are nearly 50 oil fields in Turkey, and a significant proportion of them would be potentially suitable for EOR. If sufficient volumes of CO2 were economically available, many of these could produce incremental oil for an extended period. It is a fact that sedimentary basins in the Middle East are typically carbonates, and this limits the selection of EOR processes significantly. Having observed CO2 injection as an excellent choice for carbonates through experience with the Bati Raman field, one may extend the CO2 network idea to the whole region. This will not only activate the enormous EOR potential in the mature fields of the Middle East, but also the permanent storage of CO2 through a common effort.
The use of captured CO2 for EOR will become feasible if CO2-recovery plants with a higher CO2 content give an attractive CO2 delivery cost and emission rights can be traded in the carbon market, which was introduced by the Kyoto protocol. The major challenges would be formulating a working and acceptable model between petroleum and power sectors and to establish a market mechanism to ensure that this system becomes economically feasible.
Perspectives on CCS Cost and Economics
Authors: Kheshgi H.S.. S. , Thomann H.. , Bhore N.A.. A. , Hirsch R.B.. B. , Parker M.E.. E. , Teletzke G.F.. F. 
Published: June 2014

Summary
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 with other options in the future depends critically on the cost of CCS (the focus of this paper) and resolution of barriers to CCS deployment and costs and barriers for other emission-reduction options.
This paper provides a comparison of the cost of electricity of five power-generation options—gas combined cycle gas turbine (CCGT) and supercritical coal 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 USD 60 to 100/t of CO2 avoided, which is higher than some of the earlier CCS estimates, and higher than the generally accepted range of expected carbon prices in the next 2 decades. The high cost of coal CCS suggests that Gas-based power generation is significantly more economical than coal CCS at carbon prices less than USD 60 to 100/t CO2.Even after carbon prices reach USD 60 to 100/t CO2, gas CCS produces lower-cost electricity than coal CCS, as long as natural-gas prices remain less than USD 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 2 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 [e.g., natural-gas processing and enhanced-oil-recovery (EOR) operations]. In the natural-gas-processing industry, CO2 separation cost is a fraction of the cost of CO2 capture in power generation because of 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 in power generation because the CO2 streams are typically smaller scale and more distributed than those from large power plants.
Realistic cost estimates for CCS and for other greenhouse-gas (GHG) mitigation options are an important input for focusing research, development, and demonstration addressing barriers to applications that show the greatest promise and for development of sound policy.
Characteristics of Slug Flow in a Vertical Riser
Authors: Abdulkadir M. , Hernandez-Perez V. , Abdulkareem L. , Lowndes I. S. , Azzopardi B. J. 
Published: June 2014

Abstract
This paper presents the results of a series of experiments conducted on a vertical 67 mm internal diameter riser to study the characteristics of slug flow generated within a multiphase air-silicone oil mixture, for a range of injected superficial gas and liquid flow rates. Air/ silicone oil flows in a riser have been investigated using advanced instrumentation called Electrical Capacitance Tomography (ECT), described in Hammer (1983), Huang (1995) and Zhu et al. (2003). The ECT was used to determine: the velocities of the Taylor bubbles and liquid slugs, the slug frequencies, lengths of Taylor bubbles and liquid slugs, the void fractions within the Taylor bubbles and the liquid slugs over a range of superficial liquid (0.047≤USL≤0.38 m/ s) and gas (0.344≤USG≤0.745 m/ s) velocities. An examination of the experimental data concluded that the rise velocity of the observed Taylor bubbles (structure velocity) were strongly dependent on the mixture superficial velocity. The void fraction within the liquid slug and the Taylor bubbles were observed to increase with gas superficial velocity. The lengths of liquid slug and Taylor bubbles were also observed to increase with an increase in the gas superficial velocity. The liquid slug frequency was observed to increase as the liquid superficial velocity increases, but was observed to be weakly dependant on the superficial gas velocity.