bluuebunny/crossref_metadata_2025_split huggingface dataset:
Steam Flooding of Naturally Fractured Reservoirs: Basic Concepts and Recovery Mechanisms
Authors: Mollaei A. , Maini B. 
Published: March 2010

Abstract
A review of important issues in steam injection in naturally fractured reservoirs (NFRs) is presented. The effect of temperature on physical properties of crude oils and rocks and the thermo-chemical alteration of crude oil are discussed.
The recovery of oil from NFRs can be modelled as a two step process: first the oil is expelled from the matrix blocks through mechanisms that impose a pressure gradient within each matrix block and then it is swept through the fracture network to a production well by mechanisms that impose a pressure gradient within the fracture network. The recovery mechanisms associated with steam injection in NFRs and their characteristic times are presented. The most important recovery mechanism in matrix blocks is differential thermal expansion between oil and the matrix pore volume and the strongest mechanism in fracture network is the reduction of viscosity ratio (µo/µw). The matrix oil recovery mechanisms are relatively independent of oil gravity, making steam an equally attractive recovery process in fractured light and heavy oil reservoirs.
The mechanism and impact of CO2 generation during steam injection in carbonate reservoirs are discussed. The rate of CO2 generation is controlled by the rate of heat conduction from fracture into the matrix. For a specific reservoir the rate of heat conduction is a function of temperature and injection rate of steam and these can be optimized to make use of the in situ generated CO2.
Introduction
Heavy oil in naturally fractured carbonate reservoirs is an important resource, which accounts for one-third of total heavy oil worldwide. Many fractured reservoirs in the Middle East, former Soviet Union and Canada are candidates for thermal heavy oil recovery. Steam injection processes, which have been used extensively to recover heavy oil from non-fractured reservoirs, were not applied to fractured reservoirs until recently. This was primarily based on the belief that the injected steam would bypass the oil through the fractures and would be ineffective in recovering the oil. However, the results of experimental, theoretical and pilot tests which have appeared in the literature since early 1980s, show the feasibility of heavy oil recovery from fractured reservoirs using steam injection.
Numerical Simulation of In-Situ Combustion Experiments Operated Under Low Temperature Conditions
Authors: Sequera B. , Moore R.G. , Mehta S.A. , Ursenbach M.G. 
Published: March 2010

Abstract
During in-situ combustion (ISC) processes, different chemical reactions occur depending on the temperature level. In heavy oils and bitumens, low temperature oxidation (LTO) reactions dominate below 300ºC, increasing the density and viscosity and producing coke which could prevent the success of ISC. Above 350ºC, combustion reactions dominate, known as high temperature oxidation (HTO), producing carbon oxides and water. Numerical models tend to include only thermal cracking and HTO reactions, as LTO reactions are not well understood. In the present work, ISC experiments operated under LTO were simulated, using Saturates, Aromatics, Resins and Asphaltenes (SARA) fractions to characterize the Athabasca bitumen. Concentration profiles and coke deposition for individual temperatures were matched for isothermal experiments from 60ºC to 150ºC. Based on these results, ramped temperature oxidation (RTO) experiments were then modelled, incorporating the heat of reaction at LTO. Different reaction models were studied to match temperature profiles along the reactor, oxygen consumption, coke formation and fluids production. This research will greatly increase the understanding of LTO reactions occurring in Athabasca bitumen during ISC and contribute to the creation of a reliable numerical model that predicts ISC performance under ideal (HTO) and, importantly, non-ideal (LTO) temperature conditions.
Introduction
ISC is a promising but complex oil recovery process in which thermal energy is generated inside the reservoir owing to combustion reactions between the heaviest fractions of the oil and an injected oxygen containing gas. For heavy oils and bitumens, ignition temperatures above 350°C are required to promote the combustion reactions (HTO). At lower temperatures, other types of reactions predominate, involving the addition of oxygen to the bitumen, producing heavier oxidized compounds. The LTO reactions are detrimental to oil production; hence, ISC processes are designed to operate under the high temperature combustion regime (HTO). However, LTO reactions occur if the air flux becomes too low to sustain the combustion reactions, leading to lower-than-estimated production yields. It has been proven in laboratory experiments that oil recovery is considerably reduced when LTO reactions occur to some extent, compromising the success of the ISC.
Simulating the ES-SAGD Process With Solvent Mixture in Athabasca Reservoirs
Authors: Deng X. , Huang H. , Zhao L. , Law D.H.-S. , Nasr T.N. 
Published: March 2010

Abstract
The ES-SAGD process was developed to improve the energy and oil drainage efficiency of the SAGD process. The idea of the ES-SAGD process is to co-inject solvent with steam and the co-injected solvent mixes with the bitumen to further reduce the viscosity of the heated bitumen along the boundary of the steam chamber thus enhances the oil recovery. Practically, the co-injected solvent will be a solvent mixture (such as diluent /naphtha) because of its availability and reduced cost than a pure hydrocarbon. This paper reports the results of an ES-SAGD lab test conducted with steam and diluent co-injection using Athabasca bitumen. To simulate the ES-SAGD test, a pseudo-component scheme to represent the complex solvent mixture in the numerical model is derived, based on the diluent composition and measured PVT data. The behaviours and effects of the co-injected solvent in the ES-SAGD process are analyzed through detailed history matching of the ES-SAGD test. Numerical sensitivity analyses are also performed to investigate the effects of some key parameters in the numerical approach.
Introduction
The Steam Assisted Gravity Drainage (SAGD)(1) and the Vapour Extraction (VAPEX)(2), combined with the horizontal well technology, are being developed to recover the enormous heavy oil and bitumen resources in Western Canada. The SAGD process has been successfully field-tested and is in the early stage of commercial-scale application, while the VAPEX process is still at the piloting stage. Both processes have their advantages and disadvantages. The advantage of the SAGD process is its high oil production rate. However, the high production rate of the SAGD process is associated with intensive energy consumption and CO2 emissions from burning natural gas to generate steam, and costly post-production water treatment. The VAPEX process, on the other hand, has the advantage of lower energy consumption and water usage, and therefore less CO2 emission and water treatment cost. However, the major drawbacks of the VAPEX process are its relatively lower oil production rate and the additional cost of solvent.
Feasibility of Monitoring Gas-Hydrate Production With Time-Lapse Vertical Seismic Profiling
Authors: Kowalsky Michael B. , Nakagawa Seiji , Moridis George J. 
Published: March 2010

Summary
Many studies involving the application of geophysical methods in the field of gas hydrates have focused on determining rock-physics relationships for hydrate-bearing sediments, with the goal being to delineate the boundaries of gas-hydrate accumulations and to estimate the quantities of gas hydrate that such accumulations contain using remote-sensing techniques. However, the potential for using time-lapse geophysical methods to monitor the evolution of hydrate accumulations during production and, thus, to manage production has not been investigated. In this work, we begin to examine the feasibility of using time-lapse seismic methods—specifically, the vertical-seismic-profiling (VSP) method—for monitoring changes in hydrate accumulations that are predicted to occur during production of natural gas. A feasibility study of this nature is made possible through the coupled simulation of large-scale production in hydrate accumulations and time-lapse geophysical (seismic) surveys. We consider a hydrate accumulation in the Gulf of Mexico that may represent a promising target for production. Although the current study focuses on one seismic method (VSP), this approach can be extended easily to other geophysical methods, including other seismic methods (e.g., surface seismic or crosshole measurements) and electromagnetic surveys. In addition to examining the sensitivity of seismic attributes and parameters to the changing conditions in hydrate accumulations, our long-term goals in this work are to determine optimal sampling strategies (e.g., source frequency, time interval for data acquisition) and measurement configurations (e.g., source and receiver spacing for VSP), while taking into account uncertainties in rock-physics relationships. The numerical-modeling strategy demonstrated in this study may be used in the future to help design cost-effective geophysical surveys to track the evolution of hydrate properties. Here, we describe the modeling procedure and present some preliminary results.
Numerical Modelling of Geomechanical Response of Sandy-Shale Formation in Oil Sands Reservoir During Steam Injection
Authors: Du J. , Wong R.C.K. 
Published: March 2010

Abstract
In this study, we conducted numerical simulations of steam injection into a horizontal well. A sandy-shale layer with thickness of 1 metre is located 2 metre above a horizontal injection well. The numerical simulations intend to study the variations of the stress state and the permeability in the sandy-shale layer during steam injection, and to provide useful effective stress paths for laboratory experiments to follow when testing material properties of the sandy-shale. A self-developed coupled geomechanics and thermal multi-phase flow simulator was employed to conduct the simulation cases. A strain-induced permeability model was used to describe the anisotropic permeability change of the sandy-shale caused by steam injection. The simulation results demonstrate that the permeability of 5 and 50 md for the sandy-shale in two simulation cases is sufficient to allow pore pressure dissipation to occur, therefore, preventing tensile or shear failure of sandy-shale as a result of high thermal-induced pore pressure. The stress paths within the sandy-shale are approaching the failure envelope as steam injection goes on indicating simultaneous influence of the temperature and the pore pressure on the stress state change.
Introduction
Sandy-shale formations of several metres in thickness frequently exist in oil sands deposit. Their material properties, sedimentary characteristics and distribution in a steam-assisted gravity drainage (SAGD) reservoir are important factors that determine SAGD performance and strategies of positioning horizontal well-pairs. It has been confirmed that sandy-shale formations are usually very sandy and discontinuous; therefore, they are expected to be permeable to varying degrees during SAGD operations. This is completely different from the interbedded shales that have extremely low permeability and can be considered as impermeable.
Analysis of stress state change and anisotropic permeability variation in the sandy-shale requires conducting coupled simulation of geomechanics and thermal reservoir flow. Numerical modelling of the coupled processes is historically carried out in the areas of geomechanics modelling and the reservoir simulation. Gutierrez and Lewis(1) extend Biot's theory to multi-phase fluid flow in deformable porous media. Based on their formulation, they conclude that the coupling between the geomechanics and the multi-phase flow occurs simultaneously. Thus, fully coupled system equations of deformations, multi-phase flow and heat transfer should be solved simultaneously.
Development of an Optimized Tubular Material for Thermal Slotted Liner Completions
Authors: Dall'Acqua D. , Turconi G. Lopez , Monterrubio I. , Allen M.D. 
Published: March 2010

Abstract
Use of slotted liner as a sand control device is widespread in SAGD operations in Western Canada. Operating temperatures in such thermal EOR wells can be extreme, sometimes exceeding 270°C (518°F), and the associated compressive axial mechanical strain imposed by constrained thermal expansion can load the pipe material beyond its proportional limit. Selection of an appropriate slotted liner configuration is critical to ensure that structural stability (and hence sand control) is reliably maintained during operation. Mechanical properties of the tubular material at elevated temperature strongly influence the compressive stability of the liner structure, but lower-temperature properties also affect the ease of pipe slotting on a production scale, which is typically achieved by plunging thin saw blades through the pipe wall. Common slotting issues include breakage or unacceptably high blade wear rates.
This paper describes the developmental basis for a new tubular material formulation that is specifically optimized for thermal structural stability in SAGD applications without compromising slotting performance. Elevated-temperature mechanical properties are designed to prevent compressive buckling failures and to minimize strain localization potential. Results of analytical and experimental work (including stability analysis of the liner structure, thermo-mechanical material testing, and bench-scale slotting trials) are described.

Introduction
Ongoing rapid development of bitumen reserves in Western Canada has led to an increased focus on developing robust tubular design bases for extreme service conditions in in-situ recovery schemes such as SAGD. Specifically, cemented or frictionally-constrained tubulars are subjected to thermally-induced, deformation-controlled loading that leads to a unique set of design challenges and more stringent requirements for post-yield material response than those employed in traditional elastic design. Slotted liner is used as a sand control device in a majority of SAGD wells.
Slotted liners used in thermal applications must provide a stable structure under extreme thermally-induced compressive loading in order to maintain wellbore access and to prevent excessive sand from entering the wellbore. While the deformation resistance of slotted liners depends on geometric attributes such as pipe wall thickness, slotting configuration, and slot geometry, material properties have a considerable impact on structural stability and localization resistance.
Is a Paradigm Shift in Produced Water Treatment Technology Occurring at SAGD Facilities?
Authors: Heins W.F. 
Published: March 2010

Abstract
Over the past few years, a paradigm shift has occurred in the treatment of produced water for steam-assisted gravity drainage (SAGD) heavy oil recovery facilities. The shift has been away from the use of warm lime softening (WLS), filtration and weak acid cation (WAC) ion exchange to pretreat de-oiled produced water to an approach using falling film, mechanical vapour compression (MVC) evaporation to produce steam generator feedwater. Today, approximately 16 such evaporators are operating, under construction or in various stages of delivery in Alberta and overseas.
Many new SAGD facilities are evaluating MVC evaporation as the "baseline?? approach with the "traditional?? WLS/WAC system being treated as a secondary alternative, along with other alternative approaches. This shift in methodology is because of a combination of technical and economic factors, increased reliability and availability associated with MVC evaporation and, perhaps most significantly, because of the potential to use standard drum boilers and alternative fuels for steam generation [as opposed to the use of once-through steam generators (OTSGs) required with the traditional approach]. Requirements for increased water recovery at SAGD facilities, which are made possible by MVC evaporation, also play a significant role in the shift towards produced water evaporation.
This paper presents a technical and economic evaluation of the shift towards produced water evaporation, increased water reuse and recovery, use of standard drum boilers and the use of alternate fuels at SAGD heavy oil recovery facilities.
Introduction
Over the past few years, water treatment and steam generation methods for heavy oil recovery processes have rapidly evolved. Traditionally, especially for cyclic steam operations, OTSGs, driven by natural gas, have been used to produce about 80% quality steam (80% vapour, 20% liquid) for injection into the well to fluidize the heavy oil. However, the relatively new heavy oil recovery method, referred to as SAGD, requires 100% quality steam for injection. To allow the continued use of OTSG for SAGD applications, a series of vapour/liquid separators is required to produce the required steam quality. For both SAGD and non-SAGD applications, pretreatment of the OTSG feedwater has consisted of silica reduction in a hot lime softener (HLS) or WLS, filtration and hardness removal by WAC ion exchange.
Experimental Investigation of Immiscible Gas Process Performance for Medium Oil
Authors: Zhang Y.P. , Sayegh S.G. , Luo P. , Huang S. 
Published: March 2010

Abstract
Immiscible CO2 injection is a potentially viable method of enhanced oil recovery (EOR) for medium oil reservoirs in southwestern Saskatchewan. The relatively high reservoir pressures could result in a large extent of CO2 dissolution, significant oil viscosity reduction and oil swelling. Laboratory corefloods were used to compare the performance of different modes of CO2 injection into a medium-gravity oil system. The following methods were compared: injection of a single CO2 slug chased by water, simultaneous injection of water/CO2, and different water-alternating-gas (WAG) cycles.
The results indicate that both a single CO2 slug and the first WAG cycle in a series produced oil very efficiently, possibly owing to good gas/oil contact at the relatively high residual oil saturation at this stage. The simultaneous injection of water/CO2 was not as effective as a single CO2 slug, possibly because the co-injected water shielded the oil from being contacted by the gas. Among the four runs, a coreflood with four WAG cycles recovered the most incremental oil—20.58% initial oil in place (IOIP)—while the co-injection process produced the least (8.91% IOIP).
This experimental study suggests that the immiscible CO2 EOR process is viable for medium oil reservoirs with relatively high pressures, and that proper process application is important for maximizing additional oil production.
Introduction
Miscible/immiscible CO2 flooding is an increasingly popular EOR technique. So far, most of the CO2 miscible/immiscible processes have been applied in light oil reservoirs, and there has been little application in medium oil reservoirs. The in-place resources of medium oils, defined as 20 - 30°API, in Saskatchewan are estimated at up to 1,338 × 106 m3 (8.42 billion barrels)(1). Most of these reservoirs are characterized by thin pay (2 to 10 metres in thickness) and shaly sand, and they have been under production for over four to five decades. The estimated average recovery by conventional waterflood, as listed in Table 1, is only approximately 23% IOIP because this method has generally exhibited early water breakthrough and high water cuts owing to the unfavourably high water-to-oil mobility ratio. By adapting miscible/immiscible CO2 flooding technologies that have matured in light oil applications, the immiscible CO2 process is potentially viable for recovering additional oil from these medium oil reservoirs if we can improve its displacement and sweep efficiency(2).
Computed Tomography Study of VAPEX Process in Laboratory 3D Model
Authors: Wu G.Q. , Kantzas A. , Salama D. 
Published: March 2010

Abstract
The vapour extraction (VAPEX) process has been an intense research topic in recent years as an alternative technology to thermal recovery methods for heavy oil and bitumen resources. Most previous 2D transparent models had simulated the vapour chamber evolution behaviour of a vertical slice of the reservoir; however, the longitudinal vapour chamber evolution characteristic in 3D geometry could not be detected.
This paper presents the results of 3D monitoring of the VAPEX process in a laboratory model, using computed tomography (CT) technology to investigate the vapour chamber expansion behaviour in both radial and longitudinal directions.
The results show that in 3D geometry, "V?? shape vapour chamber expansion was a localized phenomenon. The dominant characteristic was that solvent gas first broke through upward to the top, progressing through the high-permeability zone by gravity segregation, forming a vapour chamber at the top. It then expanded downward from the top as the experiment progressed. From the numerical analysis of the CT images, the in-situ porous medium's porosity, density and oil saturation profiles were obtained. The results further imply that contained gravity drainage may be the key for the success of the VAPEX process.
Introduction
For the more than 400 billion m3 heavy oil and bitumen deposits in Canada, only 10% is surface minable. The major part of the deposits has to be relied on in-situ recovery processes(1). However, because of their high viscosities and low-degree API gravities in native state(2), these reservoirs can only be recovered with low recovery efficiency by conventional methods. For example, primary recovery in the best of these heavy oil reservoirs is approximately 6% of the original oil in place (OOIP). Subsequent waterflooding can improve the recovery to an extent of 1% ~ 2% incremental of OOIP(3). In order to more effectively recover these reserves, enhanced oil recovery (EOR) or improved oil recovery (IOR) methods have to be directly applied(4). The main technology challenge is to reduce the heavy oil viscosity in-situ(5). As the oil viscosity is very sensitive to temperature, thermal recovery methods seem to be very effective and have been widely researched and piloted(6), including cyclic steam simulation (CSS), in-situ combustion (ISC), steam assisted gravity drainage (SAGD) and steamflooding(7). The SAGD process has been commercially used by several oil companies in Canada. However, the SAGD process is not always applicable for all heavy oil reservoirs; some economic constraints arise if the high cost of steam generation and excessive heat losses in some thin oil reservoirs are considered(8). As alternatives, non-thermal processes such as solvent-based processes are still a logical choice to recover such heavy oil/bitumen reservoirs(9).