bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel Scheme to Enhance Steam-Assisted Gravity Drainage Production
Authors: Holmes Michael , Gupta Subodh
Published: May 2016

Steam-assisted gravity drainage (SAGD) is the present method of choice to produce the initially immobile bitumen in oil sands. However, the unit cost of production and its energy intensity offer room for improvement through further development of the technology. Dissolved gas presents a challenge due to free gas formation upon heating. To establish equilibrium and due to local pressure gradients, this gas is pushed to the edges of the steam chamber, where temperatures are lower. The gas acts as a thermal insulator, reducing the efficiency of heat transfer between the steam and bitumen. Currently, injector wells create small axial pressure gradients which allow for gas to be swept to low pressure locations where it can accumulate and get produced.

This study presents a novel well configuration to increase gas production and reservoir sweep efficiency. By drilling the injector well shorter than the producer well and adding tubing to the toe in the producer, the gas will be swept towards the toe and produced. The hot emulsion flowing through the producer annulus will heat the toe region by conduction, allowing the steam chamber to spread progressively towards the toe.

A simulation study was conducted. Homogeneous reservoir simulations were performed and the proposed process was compared to several base cases with varying completions, fluid properties, and reservoir properties based on current oil sands projects. Heterogeneous simulations were performed with a non-porous shale baffle in varying locations. Results were compared to classical SAGD and an in-depth analysis was performed to understand the mechanisms behind the improvements and better optimize the process.

The homogeneous simulations indicate that the proposed process is very efficient at removing solution gas from the reservoir, which increases oil production rates. Steam to oil ratio (SOR), a measure of process energy efficiency, is reduced. The proposed process outperforms classical SAGD with conventional completion scheme in all heterogeneous simulations as well, both in terms of oil production rate and SOR. Simulations suggest startup can be performed the same as conventional SAGD. Overall, the proposed process is very easy to implement and offers significant benefits over classical SAGD with similar or reduced costs.
Adapting Extended-Reach, Float-in Tubular-Running Practices to SAGD Completions
Authors: Webb P. D. , MacPhail W. F. , Burke L. H. , Montero J.
Published: May 2016

High torque-and-drag (T&D) values can increase the difficulty of installing tubing in extended reach steam-assisted gravity drainage (SAGD) wells. Extra surface applied compressional force (tubing jacks) is often needed to land the tubing, leading to increased completion operation time and costs, and increased hazard potential. In many cases the likelihood of sinusoidal and helical buckling of the production tubing is also significant. A method of running tubing in extended-reach horizontal wells is presented which uses pipe floatation to reduce sliding friction in the lateral section. For SAGD wells in the subject area, the operator was able to eliminate the use of tubing jacks to run production tubing to the toe of the well. Data was acquired that allowed the comparison of tubing load conditions, both with and without the floatation method. This data was also compared with torque-and-drag (T&D) modeling results to illustrate the reduction in friction that was achieved and quantify the benefit of the method.

The method adapts principles used to float casing into wells to SAGD tubing installation, and moreover uses specifically designed floatation subs to increase the efficiency of the method. The floatation subs are used to trap air in sections of the tubing string in order to improve running forces. Once the tubing is landed, applied pressure is used to burst fragmentation domes within the floatation subs, leaving no obstructions in the tubing string.

In all trials of the float-in method, tubing was landed under its own weight, without using tubing jacks. In all of the conventional method wells, tubing jacks were needed to successfully land the tubing. Torque-and-drag models accurately predicted the point at which conventionally deployed tubing reached a neutral hookload.
New Data on The Behaviour of Asphaltenes in Thermal Heavy Oil and Bitumen Production Operations
Authors: Romanov G. V. , Ganeeva Yu. M. , Barskaya E. E. , Yusupova T. N. , Arbuzov A. E.
Published: May 2016

World heavy oil and bitumen deposits contain more than twice the amount of crude compared to conventional reservoirs. Thermal production operations are used worldwide for heavy oil and bitumen production. Because of their nature, heavy oil and bitumen have a higher asphaltene content than conventional hydrocarbons. Asphaltene behaviour is affected by changes in pressure, introduction of gas to a reservoir, acidizing and other factors, including temperature. The effect of temperature on asphaltenes in heavy oil is still not well understood.

The paper presents new data on asphaltene behaviour in thermal heavy oil and bitumen production operations. Liquid crystals in asphaltenes are detected when heat is applied. Temperature when liquid crystals appear in asphaltenes of heavy oil and bitumen is significantly lower than that for conventional oil. An assumption is made that this phenomenon is caused by the structure of asphaltenes, namely an enhanced amount of "archipelago" type molecules in asphaltenes. In situ combustion causes an increase of condensed aromatic compounds in asphaltenes, asphaltene transformation up to coke and deposition in porous media. The process changes the individual characteristics of the oil system. The individual characteristics of heavy oil do not change when steam injection technology is applied. The paper also provides data on viscosity of heavy oil and bitumen versus temperature as a function of heavy oil composition and the effect of ultrasound on heavy oil viscosity.
Unlocking Potential Of The Lower Grand Rapids Formation, Western Canada: The Role Of Sand Control and Operational Practices in SAGD Performance
Authors: Williamson H. , Babaganov A. , Romanova U.
Published: May 2016

Grand Rapids is one of the major oil sand formations in Western Canada. As in-situ production of bitumen using Steam Assisted Gravity Drainage (SAGD) continues to grow, oil sands in the Grand Rapids formation is beginning to attract more industry attention. This paper focuses on the performance of two well pairs at the Blackrod SAGD Pilot Project operated by BlackPearl Resources Inc. The geology of the Lower Grand Rapids formation, sand control selection, and operational practices will be discussed using both laboratory and field data. Petrographic data of oil sand core before and after steam injection and the potential thermal formation damage mechanisms are discussed. Differences in the performance and the key learnings of the two well pairs are presented.

The findings of the work are to be implemented during the next phase of the project and are thought to be useful to other operators developing oil sands located in the Grand Rapids formation or similar oil sand and heavy oil deposits.
A New Well Positioning Technique for SAGD Applications
Authors: Wu Hsu-Hsiang , Ahmadi Akram , Hinke Sean
Published: May 2016

The magnetic ranging method is used in many oil-field drilling applications, especially in heavy oil production. One typical example is used in the steam-assisted gravity drainage (SAGD) technique to enhance oil recovery of heavy crude oil and bitumen. Such SAGD applications require drilling two horizontal twin wells that are parallel and separated by a few meters. As a result of accumulated survey errors, it is very challenging to achieve a controlled separation and good relative well placement among wells using conventional logging-while-drilling (LWD) survey data. Current practice mainly relies on wireline technology to access one of the twin wells to generate an active ranging signal; however, this is costly and time consuming.

This paper presents a true access-independent magnetic ranging solution, designed around SAGD applications, that eliminates the need to access a target wellbore below the surface. A surface excitation is attached to a wellhead of a target well to introduce a current signal traveling along the entire target well. Concurrently, LWD gradient array sensors in a drilling well measure the induced field to determine the relative distance and direction between the two wells. This method permits operators to efficiently acquire access-independent active ranging measurements, enabling faster well placement optimization.

This paper discusses the fundamentals of the new ranging technique, including both the surface excitation and the gradient array systems. The paper also analyzes modeled responses, experimental data, and field trial results from a gradient discovery tool (GDT) to validate the proposed concept. Comparing the novel tool to the current industry standard tool, a magnetic guidance tool (MGT), the paper demonstrates that the GDT is capable of achieving accurate and valid ranging performance in SAGD applications. Furthermore, the described LWD system presents an alternative ranging tool to current wireline techniques and provides several advantages for well intersection and positioning applications that can help reduce overall time and costs.
Strain Based Design and Field Application of Thermal Well Casing String for Cyclic Steam Stimulation Production
Authors: Han Lihong , Wang Hang , Wang Jianjun , Zhu Lijuan , Xie Bin , Tian Zhihua
Published: May 2016

This paper focuses on the strain based design and field application of thermal well casing for cyclic steam stimulation process. The heavy oil is a main field of China petroleum industry, where the cyclic steam stimulation process has been widely used and playing the dominating role in production. Generally the casing damage rate is 15-30% under this process, which has resulted in a large economic cost. The high damage rate is mainly caused by the current strength design method, where both the room and elevated yield strength were considered not beyond anticipated field thermal stress. In fact the casing material will serve in cyclic thermal elastic-plastic deformation state and the single yield strength is not sufficient for long term thermal stimulation process.

This paper presented a new strain based design method for thermal casing string. New material parameters were proposed to build the safety evaluation principle throughout the service life. For thermal casing the material plasticly deforming limit, called as allowable strain, is determined by the homogeneous deforming capacity. For design strain, the material creep rate equation is introduced to evaluate the accumulative elevated strain in long term service together with initial install strain, thermal strain and soil strain. When the design strain is not more than the allowable strain the casing material will safely serve throughout the whole life. In addition the strain fatigue limit is measured to evaluate the material safety for thermal cycle life. According to the factual field engineering environment the gas tight thread joint was adopted to prevent steam leak which otherwise will cause a large transversal stress between different formations and result in slip deformation of casing string.

Before the engineering operation the full scale test procedure was proposed and finished to evaluate the string integrity in multiple thermal cycles. From 2011, this method was used in Xinjiang oil field for eight wells for more than 14 steam cycles and all the experiment wells served well without any damage. Several wells were cyclic measured through multi arms inspector and the data showed that all the casing deformation located in controlled scope except that only one has obvious deformation because poorer cementing quality. The field practice has showed that the new method has better fitness for thermal wells.
Probabilistic Analysis on the Caprock Integrity During SAGD Operations
Authors: Yang B. , Xu B. , Yuan Y.
Published: May 2016

Geomechanical simulations are often used to study the deformation and mechanical failure behaviour of caprock formations in a SAGD operation. Different assumptions are made when building the simulation models. Usually the overburden formations above the reservoir are described by a limited number of vertically separated layers with varying thickness. Each layer is assumed homogeneous with laterally uniform material properties. In many cases, these simplifications are not accurate. It is important that the simulations properly consider the vertical and lateral variations.

This paper presents a probabilistic analysis on caprock integrity using a randomized finite element simulation approach. Volume of shale (VSH) logs and X-ray Diffraction (XRD) analysis data are used to generate stochastic distribution of 3 major litho-facies: sands, shale with low illite/smectite (I/S) contents and shale with high I/S contents. The litho-facie distributions are then mapped onto the finite element discretization of simulation models. Mechanical properties of the 3 major litho-facies are measured in a geomechanical laboratory test program. The geomechanical finite element model is coupled with thermal reservoir simulation results to study the deformation behaviour of caprock during a SAGD operation. Following a number of simulations, the results are statistically analyzed to estimate the probability of the caprock to enter plastic yielding.
Experimental Evaluation of the Effect of Temperature on Wettability of the Grosmont Carbonate Reservoir in Alberta
Authors: Modaresghazani J. , Moore R. G. , Mehta S. A. , Ursenbach M. G.
Published: May 2016

A series of experiments were conducted to study the potential effect of temperature on wettability of a carbonate reservoir using contact angle measurement method. Natural core plugs which were originally drilled out of the formation, were further cut into disk-shaped core samples in order to mount them inside a custom made cell which was designed to run the high temperature and high pressure experiments. This proprietary cell was designed to hold a solid core wafers and equipped with an injection needle to create a droplet on the surface of the wafer. Having made a droplet of oil on the surface of the core sample, the temperature was ramped to elevated temperatures and the contact angles were measured continuously at certain time intervals. Experiments were conducted on both natural cores and toluene-extracted core samples.
Re-Examination of Fingering in SAGD and ES-SAGD
Authors: Ji Dongqi , Yang Sheng , Zhong He , Dong Mingzhe , Chen Zhangxin , Zhong Liguo
Published: May 2016

Steam-Assisted Gravity drainage (SAGD) is a popular approach for oil sands recovery, in which a steam chamber is developed inside reservoir with heated up bitumen flowing downwards along the edge of the steam chamber to production well by gravity. To improve the production performance of SAGD, solvent co-injection with steam (called ES-SAGD) is also proposed. In both SAGD and ES-SAGD, the penetration of low viscosity gas phase into viscous bitumen induces fingering at the steam chamber edge, resulting in non-uniform steam chamber. In this study, for the first time, the phenomenon of fingering is re-examined under the condition of mobile initial-water in oil sands through a newly designed reservoir simulation model. The effect of Solution Gas to Oil Ratio (GOR) on fingering in SAGD is also studied. In addition, the impact of solvent-water-bitumen phase behavior, which is critical to the amount of gas phase, on fingering is examined in ES-SAGD. The results reveal that fingering takes place at the oil zone on the top of steam chamber in SAGD, due to the ex-solution of solution gas under elevated temperature. The addition of solvent in ES-SAGD enhances the fingers by reducing the partial pressure of the solution gas and increasing the amount of solution gas at the top of steam chamber. It is found that the flow of the initial-water in oil sands mitigates the degree of fingering and helps stabilize steam chamber edge. This re-examination of fingering in SAGD and ES-SAGD demonstrates that the mobility of the initial water in oil sands has to be taken in account in the analysis of steam chamber instability.
Numerical Assessment of the Maximum Operating Pressure for SAGD Projects Considering the Effects of Anisotropy and Natural Fractures in the Caprock
Authors: Rahmati Ehsan , Nouri Alireza , Fattahpour Vahidoddin , Trivedi Japan
Published: May 2016

This paper presents a numerical assessment for the Maximum Operating Pressure (MOP) of a Steam Assisted Gravity Drainage (SAGD) project considering the effect of the Natural Fractures (NFs) and intrinsic anisotropy of the cap shale. Current numerical and heuristic assessments usually ignore the effect of the intrinsic and structural anisotropy of the cap shale in the caprock integrity studies.

A coupled Hydro-Thermo-Mechanical (HTM) model was developed to assess the MOP. The coupled model employed a novel constitutive model which was developed to investigate the effect of NFs and intrinsic anisotropy in the cap shale. The coupled model was validated against surface heave measurements, and later utilized in a sensitivity study to assess the MOP for cases with different number of NF sets, fracture density and fracture dip angle.

Results indicate that the MOP is highly sensitive to the fracture density and dip angle. According to the results, vertical fractures have minor effect on the MOP while oblique fractures with the dip angle between 25° to 65° significantly affect the MOP. Neglecting the NFs can lead to significant overestimation of the MOP. This highlights the necessity to include the NFs in the caprock integrity assessments.

The numerical model presented in this paper considers the intrinsic anisotropy and the presence of NFs in the cap shale, while existing mathematical tools for caprock integrity studies have not incorporated the intrinsic and structural anisotropy. Ignoring the anisotropy in caprock can potentially cause a considerable overestimation of the MOP.
Gravity Inflow Performance Relationship for SAGD Production Wells
Authors: Taubner S. P. , Lipsett M. G. , Keller A. , Kaiser T. M.
Published: May 2016

This paper presents the formulation and verification of a simple model for predicting the liquid level above steam-assisted gravity drainage (SAGD) production wells. Controlling the proximity of the liquid-vapour interface to the producer is paramount for maximizing the energy efficiency of SAGD, optimizing production, and reducing the risk of liner damage from steam breakthrough; and so a simple model can be used for quick approximation and potentially for decisions on wellbore design and operational control.

The formulation is based on continuity of mass flow and thermal behaviour. Darcy's law is the key phenomenon in formulating an analytical model of the flow through the liquid pool, or steam trap, around the production well, which is referred to in this work as a gravity inflow performance relationship (GIPR). The GIPR relates the liquid level above the producer to the inflow rate, system pressures, and reservoir and fluid properties. To validate our modelling assumptions, the liquid level predicted by the GIPR is compared to data generated from a commercial reservoir simulator for a wide range of operating conditions.

Based on data from 31 reservoir simulations, the GIPR predicts the liquid level with high accuracy. The liquid levels given by the GIPR and reservoir simulator differ by a root-mean-square error of only 0.23 m. The introduction of a correction factor in the GIPR reduces the root-mean-square error to just 0.17 m. Moreover, the GIPR reveals fundamental relationships between the liquid level and SAGD process variables, providing insight into the mechanics of steam trap control. The relationship between the liquid level and the inflow rate yields a criterion for the stability of the liquid-vapour interface above the production well. The criterion elucidates the conditions under which the position of the liquid-vapour interface will be unstable and, thus, the conditions under which steam breakthrough or injector flooding may be expected.

The GIPR provides a simple, efficient, and accurate way to predict the liquid level above SAGD production wells, enabling the optimization of well designs and control strategies to facilitate steam trap control. In addition, the GIPR reveals relationships between variables that are masked with more complex models, providing an enhanced understanding of the SAGD process.
Investigation of Post-Abandonment Surface Deformation in SAGD Operations
Authors: Hosseini Amir H. , Mostafavi Vahid , Bresee Don
Published: May 2016

Steam-Assisted-Gravity-Drainage (SAGD) has been extensively applied in thermal recovery from oilsands reservoirs in the Athabasca region of Northern Alberta. As the steam chambers associated with SAGD well pairs become mature, a form of abandonment is often applied for pressure maintenance in the depleted zone. Quantification of potential surface subsidence associated with SAGD abandonment becomes critical especially when the mature wells are in proximity of future developments. In addition, induced shear stresses should also be estimated to fulfill well integrity requirements. In this case study, a coupled reservoir – geomechanical simulation model is developed, calibrated and utilized to estimate the magnitude of post-abandonment subsidence and the induced shear stresses in Surmont SAGD Pilot Project. In the context of this study, first, the development of a simplified 2D static geomechanical model using an original geomodel realization as well as geomechanical properties and stress profiles is discussed, which forms the basis for the coupled simulation model. The calibration workflow of the coupled reservoir-geomechanical simulation model to historical heave data is then reviewed and the impacts of different parameters on calibration quality is investigated. Finally, the estimation of subsidence and the induced shear stresses in the nearby wells is discussed, and the magnitude of residual heave is quantified. The results of this study show that only a fraction (up to 40%) of surface heave is reversible (in form of subsidence) during the abandonment phase. Therefore, the magnitude of the surface subsidence and the associated shear stresses are quite small. The modeling study has also shown that a small magnitude of subsidence may be recorded even 10 years after abandonment. However, more than 50% of the surface subsidence is observed in the first two years post-abandonment. Other important findings of this study includes (1) documenting the effects of thief zone interaction as it relates to irreversibility of surface heave; (2) documenting the impacts of various geomechanical parameters on the quality of calibration against the historical heave data; (3) observation of the relative impacts of the pressure and temperature fields on the magnitude of heave; and (4) quantification of incremental, yet small, shear stresses along the nearby horizontal wells.
Approaches for CO2 Capture and Sequestration Inspired by Biological Systems
Authors: Ameur Z. Ouled , Gupta S. , Siegler Hector De
Published: May 2016

In this study, several process alternatives for the permanent sequestration of carbon dioxide (CO2) as solid carbonates are evaluated. Although the formation of mineral carbonates is thermodynamically favourable, it does not occur significantly due to kinetic limitations and the formation of products that hinder the evolution of the process. Several biological organisms, including corals, have developed different mechanisms for accelerating the process and managing undesirable products. In this report, we propose biomimicking approaches to precipitate solid carbonates while limiting the amount of energy required or using the produced by-products to generate valuable materials.

A few processes alternatives are described and evaluated in this study. In all these explored cases CO2 mineralization requires divalent cations such as Ca++ or Mg++. These could be sourced from sea water or land based silicates containing these cations. Sea-water based source results in two attractive options, namely: 1. electrochemically assisted precipitation of carbonates with production of sales of Cl2 or HCl; 2. electrochemically assisted precipitation of carbonates and production of Vinyl Chloride Monomer (VCM) and polymerization into Polyvinyl Chloride (PVC), with sales of PVC; the land based source results in further in options 3, and 4: 3. electrochemically assisted precipitation of carbonates with in-situ mining of silicates; and 4. ammonia assisted precipitation of carbonates with in-situ mining of silicates. This study explores the technical feasibility of these options further.
A Robust Automatic Well Gauging System for Heavy Oil Operations
Authors: Jones J. A. , Hammond B. R. , Keser D.
Published: May 2016

Gauging oil and water rates from heavy oil wells has historically been a difficult task. Heavy oil offers several unique problems that hinder that task. These include oil density close to the associated water density which hinders gravity separation, high viscosity which inhibits flow and proper instrumentation function, high sand production with bad implications for well testing facilities, and a tendency to form difficult oil/water emulsions. An automatic well test (AWT) system has been developed over time to overcome the problems associated with gauging thermal, heavy oil wells. This system selects a well from a group of wells with a valving system operating in hot/cold, high/low viscosity, sandy conditions and employs a test vessel that can handle high/low gross/net, sand, variable temperature, and gas if present. Tests with this system are not only reliable and much cheaper; they are done much more frequently.
A Study of Sealability Evaluation Criteria for Casing Connections in Thermal Wells
Authors: Xie Jueren , Matthews Cam , Hamilton Andrew
Published: May 2016

The severe loading conditions experienced by the casing strings in thermal wells used in Cyclic Steam Stimulation (CSS) and Steam Assisted Gravity Drainage (SAGD) operations pose a significant challenge in terms of the casing connection sealability performance and integrity. The industry has recently developed standards and protocols for assessing and qualifying connection sealing performance for such applications. The comprehensive programs include both Finite Element Analysis (FEA) evaluations and a series of full-scale physical tests. The FEA evaluations are required to determine the worst-case connection design scenarios, in terms of geometry, material properties and make-up torque, for fabrication of the specimens to be assessed in the physical tests. The scope of the FEA work includes analyzing the connection sealability performance under selected load cases representative of the intended field service conditions. A suitable minimum sealability criterion is required to assess the adequacy of the predicted connection sealing performance for the specific application.

This paper presents the results from an experimental metal-to-metal seal investigation and describes their use to establish a simplified sealability criterion for premium casing connections. The leakage response of several different seal samples was determined as a function of contact stress level for differential gas pressures of 3.3, 7.4, 12.1 and 16.5 MPa, corresponding to Application Severity Levels (ASL) of 240, 290, 325 and 350 per ISO/PAS 12835. The test results were used to characterize the relationship that existed between the leakage rates recorded in the tests and the selected control variables: differential pressure; seal length; tubular size; and seal contact stress level. The paper also demonstrates the use of the proposed sealability evaluation criterion in conjunction with the FEA results established for a 244.5 mm, 59.5 kg/m L80 premium connection subjected to thermal cycle loading.
Effect Of Geomechanics On Optimization Of Solvent Assisted SAGD SA-SAGD in Oil Sands Reservoirs
Authors: Abbasi Asl Y. , Chalaturnyk R.
Published: May 2016

It is generally accepted that solvent-steam injection in heavy oil/bitumen reservoirs outperforms steam only injection in terms of oil recovery rate, ultimate oil recovery and steam oil ratio. Important parameters in SA-SAGD design are solvent selection, injection strategy and solvent retention in situ. The role of geomechanics in optimum application of SA-SAGD, however, remains largely unexplored.

Recent studies suggest that solvent transport, solvent dilution effect and the temperature distribution around the edge of the steam chamber have major control over SA-SAGD performance. Solvent-steam injection significantly alters the temperature distribution around the chamber edge compared to steam only processes (SAGD). The temperature redistribution, in addition to the altered pore pressure, produces geomechanical effects such as porosity and permeability alteration, relative permeability changes and residual saturation alterations which in turn, influence solvent-steam-oil phase behavior and solvent transport and retention, among others. These chains of events affect the steam chamber growth and the solvent distribution, which affect optimum solvent selection and solvent-steam injection scenarios. These geomechanical considerations are of particular interest for bitumen deposits, both oil sands and carbonates, where chemical, thermal and fluid pressures can impose significant volume changes within the reservoir especially in shallower, lower confining stress settings.

The role of geomechanics in SA-SAGD was explored numerically using a sequentially coupled modeling approach with STARS (CMG) and FLAC (Itasca). A 2D homogenous oil sands reservoir geomodel at a shallow depth was considered for the purpose of this paper. Studies were conducted at two scales: 1) edge of steam chamber and 2) reservoir scale including underburden and overburden. The results of these numerical studies revealed geomechanics considerations directly affect the optimum solvent type selection and injection strategy during high pressure SA-SAGD processes. These studies provide valuable direction for further detailed mechanistic studies (both numerically and experimentally) and provide valuable input to the challenges of optimizing SA-SAGD processes in oil sands.
Clay-Asphaltene Interaction During Hybrid Solvent-Steam Injection Into Bitumen Reservoirs
Authors: Coelho R. , Ovalles C. , Hascakir B.
Published: May 2016

The goal of solvent-steam-flooding is enhancing bitumen recovery by the simultaneous development of miscibility and reduction of oil viscosity. Though this strategy reduces greenhouse gas emissions, solvents are expensive. Additionally, bitumen recovery performance is affected by oil/solvent/clay/asphaltene interactions on pore-scale. The solvent dose and type must be optimized to maximize recovery, while minimizing environmental impacts and operational costs. To investigate the performance of solvent-steam processes, six core flooding experiments were conducted on a Canadian bitumen sample with 8.8°API and 54,000 cP. Propane-steam flooding was tested and compared to steam-flooding. The effect of reservoir clays is studied by repeating experiments without clay addition. Three propane flowrates were tested to examine the impact of solvent dosages. After the experiments, asphaltene, clay, viscosity, and water content in produced oil were measured. Propane-steam flooding increased recovery factors, accelerated production, and had higher quality oil than steam-flooding. The lowest propane flowrate (1:9 vol/vol) improved oil recovery by 23%, indicating that higher solvent concentration may not be needed. This work reveals that bitumen microscopic displacement efficiency is enhanced by up to 88% with the addition of solvent to steam flooding. It is proposed that pore-scale interactions, solvent flowrate, and clays also highly influence produced oil quality and oil recovery rates.
SAGD Production Observations Using Fiber Optic Distributed Acoustic and Temperature Sensing: "SAGD DAS - Listening To Wells to Improve Understanding of Inflow"
Authors: MacPhail Warren , Kirkpatrick James , Banack Ben , Rapati Bryan , Asfouri Alex Ali
Published: May 2016

Performance optimization of steam assisted gravity drainage (SAGD) well pairs requires awareness of unique and sometimes complex downhole processes. Reservoir monitoring tools commonly used to characterize the downhole pressure and temperature environments include thermocouples, pressure gauges, and discrete or distributed fiber-optic sensors. Distributed temperature sensing (DTS), the most common fiber-optic measurement used for SAGD reservoir monitoring, has been widely adopted for SAGD production monitoring due to its ability to accurately measure a wide variety of temperatures in harsh environments. High-measurement density along the entire SAGD well length has proven to be useful for both production optimization (Krawchick et al. 2006) and well-integrity applications.

Though DTS monitoring is a primary downhole measurement tool for thermal production, other sensors may further characterize the nature of SAGD well performance when used in conjunction with DTS. Alone, temperature and pressure measurements may not yield a complete understanding of the inflow contribution in SAGD production wells. For instance, the effects of complex heat transfer may mask reservoir temperatures. Additionally, high temperatures are not always indicative of inflow and cooler liner temperatures may not signify the absence of production contribution. Distributed acoustic sensing (DAS), which is used to measure acoustic frequency and intensity in 1-m intervals along the length of a fiber-optic line, is another downhole measurement tool currently being evaluated for its ability to provide additional downhole wellbore information. Although DAS has been commonly used to characterize the acoustic environment in hydraulically fractured horizontal wells (MacPhail et al. 2012, Holley et al. 2015), it has not been extensively applied in SAGD well pairs. This paper shares select DAS and DTS monitoring data from a pilot well, the results of which improved the operator's understanding of the nature of the SAGD production.

In late 2012, Devon Canada installed DTS multi-mode fiber in several production wells at SAGD assets in the McMurray Oil Sands. Single-mode fiber utilized for DAS were deployed in conjunction with multi-mode fiber, allowing simultaneous logging of DTS and DAS data throughout the wellbore. Temperature and acoustic datasets were obtained at different representative flow conditions, including stable production, rate step-down, early time shut-in, and well startup. The combined analysis of DTS, DAS, and surface production data shows that DAS was able to identify steam flashing and qualitatively define production inflow contribution and gas/liquid composition. Due to the complex, bi-directional flow in the trial well, some of these conclusions would not have established without the observations obtained from DAS monitoring.
Modification of Butler's Unsteady-State SAGD Theory to Include the Vertical Growth of Steam Chamber
Authors: Keshavarz Mohsen , Harding Thomas G. , Chen Zhangxin John
Published: May 2016

Steam-Assisted Gravity Drainage (SAGD) is a widely used thermal recovery technique in western Canada. Use of numerical simulators, although successful in history-matching and performance prediction of the process, is extremely time consuming for field-scale optimization purposes. Therefore, analytical and semi-analytical models are desirable tools for quick field-wide performance forecast.

The first theoretical study of SAGD was conducted by Butler et al. (1981). An elegant analytical model was developed to estimate the oil production rate of a laterally spreading steam chamber, assuming a steady-state mode of thermal conduction beyond the advancing steam front. This model has been the basis for all other SAGD analytical/semi-analytical studies. The model was later modified by Butler and Stephens (1981) and Butler (1985) to overcome the shortcomings of the steady-state heat transfer assumption.

The majority of the analytical models of SAGD to date, assume that steam chamber has reached the over-burden from the start of the process and that it can only grow sideways. In real applications, however, steam chamber will rise vertically during its early stages of development. Therefore, these models are not capable of capturing the physics of the vertical growth phase adequately and their estimations of the oil production rate and steam oil ratio (SOR) may be questionable.

A uniform steam chamber development during the vertical growth is crucial to an efficient SAGD process during the rest of the project's lifetime. Therefore, it is important to have a reliable estimation of the performance of this phase. In this work, the unsteady-state SAGD model of Butler (1985) has been modified to include the vertical growth phase. Darcy's law and material balance were combined to estimate the oil production rate and steam chamber growth. Energy balance was then used to estimate SOR.

Validation of the estimations for oil production rate, steam chamber shape and SOR from this new model against the results of fine-scale numerical simulation indicates that the model has successfully captured the primary physics of the vertical growth phase. The model also predicts a more accurate in-situ distribution of thermal energy and SOR compared to the original model of Butler (1985). A closed form solution is possible for oil production rate, chamber height and SOR under some simplifying assumptions during the vertical growth phase; however, a numerical approach is required beyond this phase. The mathematics are simple enough to allow coding with simple computer programs to yield quick realistic field-scale performance predictions.
Convective SAGD Process
Authors: Sood Arun
Published: May 2016

In steam assisted gravity drainage (SAGD) process, accumulation of non-condensable gases at the edges of the steam chamber creates a resistance to heat transfer between hot steam and cold bitumen, thus slowing down growth of the steam chamber. Efficient removal of these gases from the steam chamber can substantially accelerate the recovery process.

Typical practice in SAGD is to use steam splitters and strive for a relatively uniform pressure in the horizontal part of the well, which allows for even distribution of injected steam into the reservoir. In convective SAGD process, a significant pressure gradient is deliberately created along the horizontal length of the injector well by tailoring the well completion design. Enhanced flow resistances can be fashioned by using finned tubes, static mixers, flow constrictions or simply using tube sections with varying diameters. A complementary placement of resistances in the producer well prevents short-circuiting of steam. Pressure gradients created in the injector well are translated on to the reservoir, thus allowing for a sweep of non-condensable gasses from the steam chamber.

In reservoir simulation studies, a novel convective SAGD process has shown significant improvement in oil production, with 20% higher peak production rates as compared to traditional SAGD while facilitating removal of non-condensable gases in excess of 90% from the steam chamber over the life of the well. Since fluids in the reservoir can now also move along the length of the wells, convective SAGD demonstrates a distinct advantage over traditional SAGD in heterogeneous reservoirs as horizontal barriers to flow can now be overcome with time.

Currently, a field pilot is being pursued at Foster Creek to test the validity of convective SAGD process.
On the Performance of SAGD in Athabasca Point Bar Deposit Reservoir With Top Water
Authors: Austin-Adigio Maureen E. , Wang J. , Gates Ian D. , Alvarez Jose M.
Published: May 2016

As efforts are made to exploit and recover bitumen resources in Canada, challenges presented by increasingly more complex reservoirs in the Athabasca area continue to pose a challenge to the application of the Steam-Assisted Gravity Drainage (SAGD) technology. Several studies have been done to investigate the impact of heterogeneities/complexities such as shale barriers, lean zones, top and bottom water on the performance of the SAGD process. However, the literature is deficient especially in point bar deposits with top water zones. This study examines by using thermal reservoir simulation the impact on the SAGD performance in a point bar deposit reservoir where an overlying top water and an inclined heterolitic strata (IHS) is present. The results show that where the top water is unconfined and the steam injection pressure is higher (4,000 kPa) than that of the top water zone, there is a huge loss in thermal energy but the top water does not inhibit the steam chamber development. But when compared to a relatively lower steam injection pressure (1,800 kPa), the top water continuously drains into the reservoir and reduces the size of the steam chamber. The confined top water case behaves very similar to a point bar reservoir without top water at high steam injection pressures and when compared to a relatively lower steam injection pressure, the top water does not significantly impact the SAGD performance. The IHS zone may constitute some nuisance to the steam chamber development but also helps to delay the drainage of the top water into the basal sand when steam is injected underbalance. Finally, under proper steam injection pressure condition, the top water production can be considerably delayed.
A New Foamy Oil-Assisted Methane Huff-N-Puff Method for Enhanced Heavy Oil Recovery in Thin Reservoirs
Authors: Sun Xiaofei , Dong Mingzhe , Zhang Yangyu , Li Mingzhong
Published: May 2016

A considerable portion of heavy oil resides in thin formations. In such reservoir environments, thermal recovery methods tend to be neither effective nor economical, due to significant heat loss and water resource requirements. The methane huff-n-puff process for enhancing heavy oil recovery in thin formations is an alternative that has the advantages of availability of resources and economic efficiency. However, the principal problem with such a process is the high mobility of the gas phase, relative to the oil phase, during the production cycle. In order to overcome this limitation, this paper presents a new enhanced methane injection technique, called the foamy oil-assisted methane huff-n-puff method (FOAM H-n-P). In this process, an oil-soluble foaming agent and methane are injected in a cyclic manner, but in two separate slugs. The methane provides the solution gas drive energy, and the presence of the foaming agent promotes the formation of an in situ foamy oil by trapping the released gas, which significantly enhances the effectiveness of the solution gas drive mechanism. A new experimental procedure was developed to prove that the selected foaming agent has an effective foaminess in conventional heavy oil, and to investigate, quantitatively, the effects of various process parameters on foamy oil stability in the FOAM H-n-P process. A series of experiments were conducted to evaluate FOAM H-n-P performance and to examine the effect of various foaming agent injection parameters on oil recovery. The experimental results show that foaming oil stability increases with greater foaming agent concentration, greater initial heavy oil height, a higher degree of gas bubble dispersiveness, and smaller dispersed gas bubble size. The FOAM H-n-P process can substantially improve heavy oil recovery performance. The most efficient case increases oil recovery by 43.29% OOIP, compared to the traditional methane huff-n-puff process. The above knowledge will have significant importance for the development of heavy oil resources in thin reservoirs.
Application of Low Salinity Micellar Emulsion In Chemical EOR of Heavy Oil
Authors: Sim Steve S. , Wassmuth Fred R. , Bai Jiang
Published: May 2016

In phase behavior studies of conventional oil for chemical EOR, formation of a single phase homogeneous emulsion system can be achieved only with formulations containing relatively high concentrations of synthetic surfactant. Application of the single phase micellar emulsion in chemical EOR has not been successful economically due to high cost of surfactant and surfactant loss in the reservoir. The economic picture could be much better when this technology is applied for recovery of high TAN heavy oils which can release the required amount of surfactant (petroleum soap) in-situ upon contact with the ASP solution.

This paper describes the successful formulation of an ASP system which can generate a single phase (Winsor type IV) micellar emulsion when mixed with a viscous high TAN (2.0 mg KOH/g) heavy oil. This ASP system contains commercial HPAM and NaOH in low salinity water. The micellar emulsion system, which is thermodynamically stable under very low salinity conditions, can contain as much as 33% of crude oil before transition to a Winsor type I system with a separate excess oil phase. Viscosity of the oil-in-water micellar emulsion varies with its oil content and is generally much less than 1/10 of the parent crude oil. The petroleum acid, which is a key component in the formation of the micellar emulsion, has been successfully isolated from the crude oil. Analytical results of the acid, by means of FTIR, NMR, LC-mass-spectroscopy and elemental analysis, will be presented.

The effectiveness of this ASP system in mobilization of capillary trapped heavy oil has been demonstrated with a Berea coreflood test. To ensure that adequate mobility control was present during displacement of the viscous heavy oil, separate sand-pack tests were also conducted for selection of candidate ASP solutions based on in-situ resistance factors. As a result, excellent incremental oil recovery (67% OOIP) and outstanding production rate (30% OOIP in 1 PV) were achieved during displacement of the viscous heavy oil (10,000 mPa.s) from Berea core. Residual oil saturation of the post-test core was < 7% Pore Volume.

To our knowledge, application of micellar emulsion generated from natural petroleum soap in chemical EOR of heavy oil has not been investigated extensively. Results from this study can lead to better understanding and improvement of this chemical EOR technology for heavy oil.