bluuebunny/crossref_metadata_2025 huggingface dataset:
Oil Recovery From Gas Over Bitumen (GOB) Reservoirs - Results From the AIDROH Pilot Project in Alberta
Authors: Hogue Bill , Gutiérrez Dubert , Hong Claire , Steiner Jennifer , Freeman Larry
Published: May 2015

Producing from bitumen reservoirs overlain by gas caps can be a challenging task. The gas cap acts as a thief zone to the injected steam used during oil recovery operations and hinders the effectiveness of processes such as steam assisted gravity drainage (SAGD). Moreover, gas production from the gas cap can accentuate the problem even more by further depressurization of the gas zone.

Following a September 2003 ruling by the Alberta Energy Regulator (AER), the Oil & Gas Industry in the province of Alberta, Canada, had about 130 million standard cubic feet per day of sweet gas shut- in to maintain pressure in gas zones in communication with bitumen reservoirs. This decision led to the development of EnCAID (Cenovus’ Air Injection and Displacement process), a process where air is injected into a gas over bitumen (GOB) zone and combustion gases are used to displace the remaining formation gas while maintaining the required formation pressure.

An EnCAID pilot was started in June 2006 and preliminary results were reported in 2008. After eight years of operations, the EnCAID project not only has proven to be effective at recovering natural gas and maintaining reservoir pressure; it has also shown it can heat up the bitumen zone and make the oil more mobile and amenable for production. This led to the development of the Air Injection and Displacement for Recovery with Oil Horizontal (AIDROH) process.

The AIDROH process is the second of two distinct stages. First, an air injection well is drilled and perforated in the gas cap. The well is ignited and air injection is performed to sustain in-situ combustion in the gas zone. This phase is characterized by a radially expanding combustion front, accompanied by conduction heating into the bitumen below. The second stage begins when horizontal wells are drilled in the bitumen zone. The pressure sink caused by drawing down the wells alters the dynamics of the process and creates a pressure drive for the combustion front to push towards the producers in a top- down fashion, taking advantage of the combustion front displacement as well as gravity drainage.

In light of the temperature increases observed in the bitumen overlain by the EnCAID project, a horizontal production well was drilled in late 2011 and commenced producing in early 2012. This paper provides an update of the EnCAID pilot results and presents a summary of the technical aspects of the AIDROH project, pilot results, and interpretation of the data gathered to date such as observation well temperatures, pre and post burn cores and temperatures along the horizontal producer.

Results indicate that the AIDROH process has the potential to maximize oil production from GOB reservoirs and efforts continue to be made to optimize its design and operation.
Simultaneous History Matching for Multiple Different Oil Sands Reservoir Models: Case Study of Hangingstone Demo Area
Authors: Kato Kodai , Doan Luong T.
Published: May 2015

SAGD process is highly affected by geological conditions such as reservoir heterogeneities caused by the existence of shale layers and/or Clast Breccia, impairment zones and so on. To evaluate SAGD performance with satisfactory precision, detailed geological models which reflect complex sedimentary heterogeneities should be constructed based on data such as well control points, 3D seismic data and Training Image. On the other hand, the relationships between complexity and simulation time conflict with each other. Although detailed geological models are needed, simulation time takes longer.

At Hangingstone Demo area, (Demo area), there are 24 well pairs which have been producing bitumen by SAGD process. The objective of this study is to obtain a unique set of parameters, such as permeabilities and extent of heterogeneities, from simultaneous history matching using different geological models (well pairs) from the Demo area. These parameters will be used for forecasting the performance of the nearby analogue Hangingstone Expansion area (HE area) development. At least a couple of well pairs coming from different well pads were chosen as representative models which indicate each typical type of reservoir. These are called Clean Sand rich type, Clast rich, and Sandy-IHS (Inclined Heterolithic Stratification) rich.

If different single models are applied to history matching, at least the same number of history matching studies are needed separately. Obtaining an optimum parameter combination will require a significant number of simulation runs. Furthermore, applying complex geological models for simulation requires significant time to finish running. Figure 1 shows the comparison between individual optimization and simultaneous optimization, which is our new workflow. By use of this, not only multiple different models but also different realizations for the same well pair are matched simultaneously by a single optimization without any time loss.

Our new workflow is composed of mainly 3 sections. The first one is vertical upscaling and coupling between the modeling package and reservoir simulator. The second one is the simultaneous history matching using multiple different models. The third one is the interpretation of the vertical observation well temperature data and history matching utilizing such data. This new technique along with field observation data will be discussed.
Performance Data of a Distributed Flux Burner in a Heavy Oil Heater Treater
Authors: Bartz David , Gotterba James
Published: May 2015

A common problem with oil-water separation in horizontal heater treaters processing heavy oil is thermal deformation and failure of the heater fire tube. Several factors contribute to the cause of the failure including presence of polymer in the water used for oil recovery, solids content in the oil, and design of the heater treater tank and controls. A key aspect of the tube failure is related to the internal heat transfer from the burner to the fire tube wall. Heat flux typically is concentrated around the burner flame with a resulting hot zone that forms a coking, insulating layer on the outside of the tube. Eventually the fire tube overheats and fails either by collapse or rupture.

Distributed flux burners have been installed to prevent the concentrated hot zone of the tube wall by improving temperature uniformity over the length of the tube. The distributed flux burner utilizes premixed surface stabilized combustion to extend the flame zone over the length of the fire tube, thereby reducing peak wall temperatures while increasing the effective heat transfer to the emulsion. The burner consists of a porous cylindrical ceramic matrix which provides infra-red radiation heat transfer to the fire tube wall to help maximize heat flux uniformity. The burner has been in commercial use for asphalt tank heating and fragile fluid heating for many years and recently has proven to be ideal for effective heating of heavy oil in heater treaters.

As a continuation from results presented in SPE-170172-MS in June 2014, we review recent field experience in heater treaters processing heavy oil at various locations. Improvements in life of the fire tube, throughput of the emulsion and sales oil, and thermal efficiency relative to conventional burners are presented. This paper also describes new specifications and criteria for proper sizing and operation of the distributed flux burner for retrofit of heater treaters.
Application of Novel Hyper-branched Polymer Fracturing Fluid System in Low-permeability Heavy Oil Reservoir
Authors: Liu Yueliang , Li Huazhou Andy
Published: May 2015

Hydraulic fracturing can be used in low-permeability heavy oil reservoirs for improving the production rate. It is challenging to achieve a high degree of fracturing fluid flow-back in low-permeability heavy oil reservoirs. This research investigates the application of a novel hyper-branched polymer fracturing fluid in low-permeability heavy oil reservoirs.

A hyper-branched polymer, which has numerous end groups and possesses a special highly branched three-dimensional spherical molecular structure, is characterized by Fourier Transform Infrared (FTIR) spectrophotometer. Laboratory tests are conducted to evaluate the stability of viscosity at a given shear rate, temperature and shearing resistance, reversible cross-linking property, filtration property, and proppant-carrying performance of this hyper-branched polymer fracturing fluid. The degrees of core's formation damage are compared through conducting coreflood experiments, where the cores are treated with two fluids: the hyper-branched polymer fracturing fluid and guanidine gel fracturing fluid.

The laboratory evaluation shows that the hyper-branched polymer fracturing fluid has good rheological characteristics, a high solubility in water, as well as good temperature and anti-shearing resistance. After being sheared for 90 minutes with the shear rate of 170 s−1 at 150°C, it can still be reversed to gel with high strength because of its reversible cross-linking effect. This fracturing fluid has a good antioxidant ability, which allows its basic fluid to be exposed to air for 48 h without viscosity reduction. Therefore, the basic fluid can be prepared as spare fluid in a large amount, significantly improving job efficiency on site. Meanwhile, field applications in some wells in China show that: the friction of this fracturing fluid during fracturing is about 30%-50% to that of the normal guanidine gum fracturing fluid. Thus it has an ultra-low friction feature. The flow-back rate of the fracturing fluid can reach as high as 80%. Besides, its cost is about 75% to that of the normal guanidine gum fracturing fluid, making it a clean and cost-effective system. The fracturing fluid prepared with hyper-branched polymer possesses outstanding technical advantages as well as good cost effectiveness, implying a promising application in the large-scale fracturing stimulation of low-permeability heavy oil reservoirs.
Steam Injection Schemes for Bitumen Recovery from the Grosmont Carbonate Deposits
Authors: Song Qiuyue , Chen Zhangxin (John) , Ali S. M.
Published: May 2015

The hydrocarbon resources in the Grosmont carbonate deposits in Alberta are over 400 billion barrels. Pilots have been carried out in Grosmont since 1974, but hitherto a commercial recovery scheme remains elusive. This study addresses oil recovery techniques from the Grosmont carbonate deposits, using numerical simulation for several steam-based recovery schemes. Selected simulation results were further analyzed and compared with those from the classical analytical model.

Given the extremely heterogeneous nature of the deposits (karsted, fractured, and high variability in formation properties) and high oil viscosity (2-11 million cp at 20 °C), a typical geological model of Grosmont, with representative petrophysical and geological characteristics, was used to examine several steam injection schemes, using a dual porosity/dual permeability model in CMG STARS. The schemes tested included: single vertical well cyclic, single horizontal well cyclic, steam assisted gravity drainage and steamfloods involving five-spot, nine-spot, seven-spot patterns and the vertical well injector-horizontal well producer arrangement.

The dominant feature of all steam injection schemes was a high steam-oil ratio, although the oil recovery was high in most cases. Experiments showed that the steam-oil ratio of steamfloods can be improved by reducing the steam injection rate and closing certain perforation intervals at critical points in the production life of the well. As a result of optimization, a pattern steamflood case achieved a steam-oil ratio of 8 m3/m3 and recovery factor of 41%. The best horizontal well CSS case, for which the well location is chosen to avoid steam channelling into the top water, gave a good response with a steam-oil ratio as low as 7 m3/m3 and a recovery factor of 18%. The recovery factors of the two processes are comparable considering the fact that the wells in the former were perforated into Grosmont C and D members of the model while the latter targets only the Grsomont C member. SAGD cases have similar steam-oil ratio but smaller oil recovery.

Simulation results were analyzed in the light of dynamic fluid flow, thermal efficiency and drive mechanism and were compared with results from classic analytical methods. Affected by the high fracture vertical permeability and severe heterogeneous formation properties, steam override and oil gravity flow occur in all processes. Uneven steam zone and limited drainage area make it difficult to achieve optimal performance of processes including SAGD, seven-spot pattern steamflood and horizontal well CSS. Early steam breakthrough happened in the pattern steamfloods. A combination of vertical steam injectors and a horizontal producer provided the most uniform formation heating and production of the mobilized oil by both gravity flow and viscous drive, thus achieved the same recovery performance faster than horizontal well CSS and delayed steam breakthrough.
History Matches and Interpretation of CHOPS Performance for CSI Field Pilot
Authors: Chang Jeannine , Ivory John , London Mike
Published: May 2015

CHOPS (Cold Heavy Oil Production with Sand) is a primary production recovery method used in the Western Canadian Lloydminster heavy oil region which contains about 3 billion m3 of heavy oil. It increases heavy oil production rates by creating high permeability channels in the reservoir through aggressively producing sand with the oil. As a result of CHOPS, 5 - 15% of the initial oil can be recovered.

This paper summarizes CHOPS history matches that used the CMG STARS™ simulator and representative process mechanisms in simulating two Husky CHOPS wells, one well was later used as a Cyclic Solvent Injection (CSI) pilot well and the second well was a communicating offset well during CSI. The history matches were pre-processed for the post-CHOPS CSI field pilot. They were part of the $40 million JIVE Program and were in support of a CSIfield development in the Edam area.

The history matches predicted the reservoir conditions (e.g. pressure, effective permeability, effective porosity, fluid saturations, and mole fraction profiles) at the end of CHOPS to set up the CSI initial reservoir conditions (i.e. the start of CSI). Oil, water and sand production were well matched for both of the wells during CHOPS. Foamy oil and sand transport mechanisms were represented in the simulations. The simulation results and the CHOPS model described below provided insight into CHOPS depletion mechanisms and post-CHOPS reservoir characteristics.

At the end of CHOPS, the CSI well was pressure depleted with low liquid inflow. In the simulations, the wormholes were predicted to extend to about 151 m from the CSI well. Wormholes from the offset well reached a source of water and had continuous water inflow. It was predicted that the offset well wormholes penetrated about 220 m into the reservoir.

Conclusions include: The AITF CHOPS model can capture field production mechanisms and reservoir behaviors.Continuing lower rate sand production and wormhole network growth is essential to obtain sustained higher oil production rates during CHOPS.As a result of greater reservoir contact, a thinner pay with longer wormholes can produce more oil than a thicker pay with shorter wormholes.Directly obtaining reservoir properties from the field LAS log data and use of the thin layers in the log file as simulation layers were important in catching fluid flow behaviors and obtaining satisfactory history matches for oil and water production.Good CHOPS history matches and reservoir charactisation are essential for field CSI pilot wells as they quantify the post-CHOPS reservoir conditions, the extension of wormhole networks, and the depletion regions. Consequently, they provide predictive value for developing CSI operation strategies for successful post-CHOPS CSI applications.
History Match and Strategy Evaluation for CSI Pilot
Authors: Chang Jeannine , Ivory John
Published: May 2015

This paper summarizes a project that was part of the $40 million 2006-2010 Joint Implementation of Vapour Extraction (JIVE) pilot program managed by the Petroleum Technology Research Centre and including Husky Oil, CNRL, NEXEN, Alberta Innovates–Technology Futures, and the Saskatchewan Research Council. The project was in support of a cyclic solvent injection (CSI) field pilot in the Lloydminster region of Saskatchewan that was evaluating the potential of CSI to exploit reservoirs following cold heavy oil production with sand (CHOPS).

History matches were performed for two Edam CHOPS wells in the Colony formation and they determined initial reservoir conditions (e.g. pressure, effective permeability, porosity, fluid saturations, and gas and oil phase mole fractions) for subsequent CSI simulations. Thin formation layers (~15 cm) were used in the CHOPS simulations to improve representation of wormhole generation and advance. One well had rapid sand production that quickly declined whereas the other well had continuous sand production due to wormhole propagation and scouring and resulted in sustained oil production.

The reservoir model for the application of CSI contained a number of wells including the CSI well and two communicating offset wells (Figure 1). Using an Alberta Innovates–Technology Futures (AITF) CSI model, a history match was obtained for CSI Cycle 1. Eleven different potential injection/production strategies were then evaluated for Cycle 2 and the simulation results were used in the design of this cycle. One conclusion was that expanding the solvent injection period from 1 to 2 months increased the combined oil production for the three wells by 29% but resulted in a 46% increase in net solvent to oil ratio. Figure 1Conversion from post-CHOPS radial geometry to Cartesian geometry for CSI simulations
Determination of Two-Phase and Three-Phase Relative Permeabilities in Heavy Oil/Water/Gas Systems
Authors: Modaresghazani J. , Moore R. G. , Mehta S. A. , Fraassen K. C.
Published: May 2015

An experimental study was conducted to investigate the relative permeability behaviour of a typical Canadian bitumen, water and gas. Series of isothermal core flood experiments were conducted on an unconsolidated core composed of cleaned Athabasca sand matrix and relative permeabilities of the involved phases were determined. Athabasca bitumen was used as the oil phase and distilled water and nitrogen were used as water phase and gas phase respectively. A vertical sand-pack core-holder of 1.5 inch diameter and 2 feet long was designed and fabricated to perform sequential injection of oil, gas and water at reservoir temperature and pressure, while collecting information on pressure drop across the core and fluid volumes. The history match technique was used to determine relative permeabilities for two-phase and three-phase water/oil/gas systems.
Improving Horizontal Well Placement in the Orinoco Oil Belt with the Use of Bed Boundary Mapping Technologies
Authors: Cuadros G. , Chamat E. H. , Villarroel N. , Scrofina J. , Cermeño E. , Rodriguez O.
Published: May 2015

The success of a horizontal drilling campaign depends on the implementation of appropriate technologies and procedures to manage uncertainties and risks that may affect the overall economy of the project. This is the case for most fields in the Orinoco oil belt—the largest reserve of heavy oil in the world—which is mainly developed via horizontal drilling. As with other fields in the area, Junin-6 presents special challenges for horizontal well placement. The friable shallow reservoirs include some of the shallowest currently developed in the Orinoco oil belt. The main target sands range in thickness from 30 ft in the Arenas Basales (Basal sands) to 250 ft in the Oligoceno (Oligocene) reservoir. The lateral sections vary from 3,000 to 4,000 ft. This, combined with a high geological complexity, lack of 3D seismic data, and a limited number of correlation wells, makes the horizontal well placement a real challenge in many cases.

Advanced logging-while-drilling (LWD) technologies had to be implemented in the challenging cases, such as in the Basal sands reservoir. A proactive approach based on bed boundary mapping technologies, combined whenever possible with point-the-bit rotary steerable systems, is being used to improve horizontal well placement in this field.

The main results include net pay increase and cost reduction compared to wells executed with conventional technologies. The risk of unproductive drilling has been considerably reduced, especially in the thinnest formations drilled in this field. The best results were achieved when LWD bed boundary mapping was combined with point-the-bit rotary steerable systems, since this type of technology enabled better well trajectory control, faster execution, longer horizontal sections, and safer completions.

This paper presents the main challenges for horizontal well placement in the giant Junin-6 heavy oil field and how they are being addressed with the use of advanced geosteering technologies.
Evaluating SAGD Performance due to Changes in Well Spacing and Length
Authors: Verney M. J.
Published: May 2015

Over the past several years, there has been a shift to drill longer wells with tighter inter-well spacing in projects using steam assisted gravity drainage (SAGD). An understanding of the impact on performance as a result of different well length and spacing can justify such a change for future well drilling. This paper examines the performance from various McMurray formation SAGD projects in the Athabasca region that have well pairs that are developed at different lengths and spacing. Changes in bitumen rate per well-pair, recovery factor and steam to oil ratio (SOR) were assessed at different well lengths and inter-well spacing. Certain performance characteristics from pads with tighter inter-well spacing were better than wider spaced pads. Furthermore, no significant changes in performance were noted in regards to changes in length.
Dissolution and Mobilization of Bitumen at Pore Scale
Authors: Bayestehparvin B. , Abedi J. , Ali S. M.
Published: May 2015

Steam injection, in various forms, has been commercially successful for in situ recovery from the oil sands. One of the recovery methods being tested – with an aim to reduce steam requirement – involves the injection of a suitable solvent, by itself, or in combination with steam. Solvents are being utilized at a pilot scale in both cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD) processes. The present study examines the mixing of a solvent with bitumen at the pore scale, using an analytical model with typical field data.

The convective diffusion equation is solved for a spherical geometry, and applied to a drop of bitumen is a pore space. Calculations are done for a number of solvents, viz. pentane, and hexane. The rate of bitumen dissolution is determined for both static and dynamic conditions, for a number of velocities corresponding to typical field injection rates. The diffusion coefficients are taken from the latest laboratory data reported. Calculations are also done for heating of the bitumen (without solvent) for the same conditions. The resulting bitumen viscosity is compared as a function of time, for both solvent injection and heating.

Results show that the time of solution of a bitumen drop in the solvent is of the order of days. The time varies with the type of solvent (largest for pentane), and the injection velocity. The times to attain the same viscosity by solvent injection in one case, and conduction heating in the other, respectively, differ by orders of magnitude. The significance of this finding for field application of solvents is discussed.

The outcome of this research will improve our understanding about solvent diffusion and dispersion process for bitumen in porous media. This will help us to modify the current modelling approach to capture more realistic mass transfer and solvent/bitumen interaction in porous media.
Investigation of Nanoparticle and Surfactant Stabilized Emulsion to Enhance Oil Recovery in Waterflooded Heavy Oil Reservoirs
Authors: Pei H. H. , Zhang G. C. , Ge J. J. , Zhang J. , Zhang Q. , Fu L. P.
Published: May 2015

Emulsion flooding has great potential for enhancing the recovery of heavy oil, especially for reservoirs in which the oil recovery by water flooding is low and thermal methods are not suitable. This study presents a study of nanoparticle-surfactant stabilized emulsion to enhance heavy oil recovery in waterflooded heavy oil reservoirs. The phase behavior tests and rheology studies were first performed to investigate the influence of nanoparticle on the stability and bulk rheological properties of the emulsion system. Then, the core flooding and microscopic visualization tests were conducted for investigating the displacement mechanisms for enhanced heavy oil recovery by nanoparticle-surfactant stabilized emulsion. The phase behavior tests and rheology studies show that the addition of nanoparticles can not only improve the stability of the emulsion, but also greatly increase the bulk viscosity of emulsion. The core flooding conducted with the emulsion co-stabilized by nanoparticle and surfactant show a marked improvement in oil recovery over the surfactant-stabilized emulsions. The tertiary oil recovery can reach over 40% of the initial oil in place (IOIP) for crude oil with the viscosity of 350 mPa•s at 50 °C. The micromodel tests indicate that the nanoparticles can thicken the emulsion to the desirable mobility, which can damp the viscous fingering phenomena to dramatically improve sweep efficiency. In addition, the heavy oil can be emulsified into the water phase to form oil-in-water emulsions with the aid of the surfactant. These results demonstrate that the nanoparticle-surfactant stabilized emulsion has a great potential for enhanced oil recovery in waterflooded heavy oil reservoirs.
Chemical Additives and Foam to Enhance SAGD Performance
Authors: Li Ran , Etminan S. Reza , Chen Zhangxin
Published: May 2015

SAGD (steam assisted gravity drainage) is known as the main technology to tackle the exploitation of heavy oil and oil sand resources in Alberta. The oil industry seems to be well-educated today about SAGD's challenges and opportunities. Enhancing the efficiency of SAGD operations remains an area of investigation as it is tied to economic and environmental measures. Use of chemical additives and foam with SAGD is a strategy proposed on this account.

Foam is dispersion of gas in a continuous water phase with thin films (lamella), acting as a separator. Given its sensitivity to oil distribution, foam tends to reside in higher permeability layers with less residual oil. Thermally stable surfactants are essential to maintain the foam life because surfactants stabilize lamella by decreasing the water-gas interfacial tension. Adding surfactants also lowers the interfacial tension at the water-oil interface and further produces water in oil or oil in water emulsion. In situ emulsion generation is thus another active mechanism that is involved as a result of surfactants presence.

Due to the above properties, steam movement is hindered, and gravity override is consequently limited, thereby resulting in high injection pressure that thoroughly displaces oil. Also, foam injection is conducive for blocking thief zones and decreasing channeling. In terms of emulsification, oil in water emulsion flow decreases water permeability created by emulsion droplets entrapment in throats, transferring the injection flow into poorly exploited areas. More trapped oil is mobilized by interfacial tension drop. The existence of water in oil emulsion contributes to heat transfer because the generation reaction is exothermic. All mechanisms mentioned are incorporated to illustrate CAFA-SAGD (chemical additives and foam assisted SAGD) performance and compare it with SAGD in both homogeneous and heterogeneous reservoirs using CMG® STARS. The reservoir under study is analyzed with low permeability layers, top water, bottom water, and lean zones for the heterogeneous case. The surfactants properties and foamibility are considered through appropriate reactions introduced into the simulator. The phase behavior for emulsification regulates different relative permeability regimes into the oil flow. We find that adding additives contributes to higher production and leads to less steam consumed.

This study incorporates viscosity reduction, mobility control, interfacial tension drop, and emulsification mechanisms to present the effects of chemical additives and foam towards SAGD performance. Our results indicate that using additives with SAGD can maintain a uniform steam chamber growth while reducing the heat loss to overburden. It has a significant long-term oil production capability.
Successful Application of Hot Water Circulation in the Pelican Lake Field - Results and Analyses of the E29 Hot Water Injection Pilot
Authors: Duval Kirk , Gutiérrez Dubert , Petrakos Dino , Ollier Pierre , Johannson Darren
Published: May 2015

The Pelican Lake field in northern Alberta (Canada) is home to the first successful commercial application of polymer flooding in higher viscosity oils (i.e. greater than 1,000 cp), which has opened up new opportunities for the development of heavy oil resources.

The field produces from the Wabiskaw “A” reservoir which has thin pay (2 to 6 meters) and exhibits a significant viscosity gradient across the field, with oil viscosities as low as 600 cp in the existing waterflood and polymer flood area to over 200,000 cp in the current undeveloped “immobile” area. This unique geological feature limits the application of chemical injection to the less viscous areas of the field and calls for different methods for the heavier accumulations.

As a first step to develop alternate technologies capable of recovering oil from heavier areas of the field not ideal for polymer flooding, a hot water injection pilot was designed and implemented in June 2011. The hot water injection scheme was applied to a transition area where dead oil viscosity ranges from 3,000 cp to approximately 15,000 cp. It consists of one horizontal producer supported by two horizontal hot water injectors, with an injector-producer distance of 50 meters for both injectors, and 3 vertical observation wells equipped to monitor pressure and temperature between one injector and the producer.

The pilot was operated in three phases. The first phase consisted of 6 months of primary production period to obtain a baseline of the pilot performance prior to hot water injection. The second phase began in June 2011 and consisted of hot water injection through the edge injectors. The third phase was started in March 2012 and consists of hot water edge injection accompanied by hot water circulation in the production well as a means to stimulate oil production. One of the features of this stage is the use of an insulated coil tubing, which continuously delivers hot water to the toe of the producer and allows continuous stimulation and uninterrupted oil production.

This paper describes the mechanical components of the pilot and discusses the results obtained with an emphasis on the hot water circulation stage which has proven to be very effective. Oil production increased from approximately 6 m3/d during the flood stage, to more than 25 m3/d during the hot water circulation stage and has held relatively steady for more than 2 years.

The data captured has been reconciled with analytical and reservoir simulation models, and results suggest that the technology could help unlock some of the heavier oil accumulations in the field.
Modelling of Non-Condensable gas Injection In SAGD Process - Important Mechanisms And Their Impact On Field Scale Simulation Models
Authors: Nourozieh Hossein , Ranjbar Ehsan , Kumar Anjani
Published: May 2015

Field-scale simulation of non-condensable gas injection in a hybrid SAGD process for the heavy oil and bitumen reservoirs requires a comprehensive numerical model that considers different mechanisms involved in the processes. The complexity of modelling such processes is due to the interrelation of oil-gas phase behavior and fluid transport mechanisms such as advection, dispersion, and dissolution. The non-condensable gas in the vapour phase is transported into the reservoir by the advection process which is dominantly controlled by the rock-fluid interaction parameters.

The steam and non-condensable fluid in the gaseous phase may have different relative permeability and end-point saturations associated with their interaction with oil/liquid. The diffusion and dispersion of non-condensable gas control how it spreads within a phase and its dissolution into oil and water determines its transfer across phases. Although, it is still debated that non-condensable gas accumulates at the steam front reducing heat transfer into the oil phase and lowering oil production rate, some field production data show contrary results. That is, the co-injection of non-condensable gas with steam does not affect the oil production rate while it reduces the steam-oil ratio. The non-condensable gas may accumulate at the top of the reservoir providing an insulation effect, reducing heat losses to the overburden and increasing the thermal efficiency of steam.

This study attempts to provide insights about field scale simulation of non-condensable gas injection in the hybrid SAGD process with a comprehensive numerical simulation model. Analysis will be presented regarding important mechanisms that should be considered, their impact on the process, and techniques to model them. Some of the important mechanisms that will be discussed are diffusion and dispersion, and solubility of gas in bitumen and water. The intent is to identify factors important to the modeling of these processes at field scale and how robust simulation models can be developed to replicate observed field behaviour.
InSAR Natural Reflector Survey for Surface Heave and Steam Chamber Monitoring at a SAGD Site
Authors: Tang K. , James B. R. , Aguado V.
Published: May 2015

This paper presents a case study of the application of an Interferometric Synthetic Aperture Radar (InSAR) natural reflector (NR) survey to monitor surface heave and steam chamber growth at one of Suncor's steam assisted gravity drainage (SAGD) fields. InSAR is a satellite technology mainly used to monitor ground motion. An InSAR NR survey relies on back scattered signal from the ground surface itself as opposed to fixed corner reflectors (CRs) which are metallic trihedrals specially designed to reflect a radar signal. This allows a NR survey to cover large areas of ground compared to those carried out using corner reflectors, but at a lower accuracy. As such, InSAR NR surveys provide a potential way of monitoring surface heave that covers much of a SAGD field at very low cost.

Results from the NR survey are very promising. First, the trends in the surface heave measured by the NR survey were almost as accurate as those measured by the CRs. In addition, the NR survey provided useful data over about 50% of the target area. This dense coverage was unexpected since the test site is covered by small trees and extensive areas of muskeg, which will interfere with the reflected radar signal.

Reliable surface heave estimates could be made in topographically high areas and in areas with gentle slopes because of their drier nature. By contrast low lying areas that were generally wetter provided little to no reliable data, hence masking any surface heave.

Benchmarking of InSAR NR data to temperature fall offs found that the NR measured heave compared well to steam chamber conformance on overall average trends. In addition, manually measured heave also compared well to steam chamber growth measured by 4-D seismic. In conclusion, results indicate that an InSAR NR surface heave survey provides a promising way of measuring surface heave and steam chamber growth over large areas of SAGD fields. It is complementary to 4-D seismic, but at as little as one hundredth of its cost.

One of the limitations of a NR survey is that measurements must be taken in non-snow time. Areas of denser forest cover may not provide as much spatial coverage with NRs as was found at the target region discussed in this paper. InSAR coverage in these areas could be done using CRs.
New Insight on Carbonate Heavy Oil Recovery: Pore Scale Mechanisms of Solvent Alternating CO2 Foam/Polymer Enhanced Foam Flooding
Authors: Telmadarreie Ali , Trivedi Japan
Published: May 2015

Carbonate reservoirs, deposited in the Western Canadian Sedimentary Basin (WCSB), hold significant reserves of heavy crude oil that can be recovered by non-thermal processes. Solvent, gas, water, and water alternating gas injections are the main methods for carbonate heavy oil recovery in the WCSB. Due to the fractured nature of carbonate formations, many advantages of these production methods are usually contrasted by their low recovery factor. Alternative processes are therefore needed to increase oil sweep efficiency from carbonate reservoirs. Foam/polymer enhanced foam (PEF) injection has gained interest in conventional heavy oil recovery in recent times. However, the oil recovery process by foam, especially PEF, in conjunction with solvent injection is less understood in fracture heavy oil carbonate reservoirs. The challenge is to understand how the combination of surfactant, gas, and polymer allows us to better access the matrix and efficiently sweep the oil.

This paper introduces a new approach to access the unrecovered heavy oil in fractured carbonate reservoirs. CO2 foam and CO2 PEF were used to decrease oil saturation after solvent injection, and their performance was compared with gas injection. A specially designed fractured micromodel was used to visualize the pore scale phenomena during CO2 foam/PEF injection. In addition, the static bulk performances of CO2 foam/PEF were analyzed in the presence of heavy crude oil. A high definition camera was utilized to capture high quality images.

The results showed that in both static and dynamic studies the PEF had high stability. Unlike CO2 PEF, CO2 foam lamella broke much faster and resulted in the collapse of the foam during heavy oil recovery after solvent flooding. It appeared that foam played a greater role than just gas mobility control. Foam showed outstanding improvement in heavy oil recovery over gas injection. The presence of foam bubbles was the main reason to improve heavy oil sweep efficiency in heterogeneous porous media. When the foam bubbles advanced through pore throats, the local capillary number increased enough to displace the emulsified oil. PEF bubbles generated an additional force to divert surfactant/polymer into the matrix. Overall, CO2 foam and PEF remarkably increased heavy oil recovery after solvent injection into the fractured reservoir.

The results of these direct visualization experiments improve our understanding of the heavy oil recovery process by solvent alternating CO2 foam/PEF flooding in fractured reservoirs. Besides enhancing oil production, application of CO2 foam/PEF may require the injection of a lesser amount of solvent into the reservoir, providing economic and environmental advantages.
Case Study of Flue Gas Assisted SAGD in Offshore Heavy Oil Reservoirs
Authors: Zhao Shunqiang , Sun Yongtao , Sun Yubao , Wu Yongbin , Liu Xueqi
Published: May 2015

A large number of heavy oil deposits in Bohai Bay in China are deep (>1500m) and extra-viscous (>20000mPa.s@50°C), which are not feasible for conventional thermal recovery methods. For these reservoirs, co-injection of steam and flue gas directly from steam generator to carry out CSS has been proven successful by pilot tests. While the oil recovery factor of CSS is estimated to be less than 20%, which poses a high economic risk under offshore condition. In order to massively enhance the recovery factor, the Flue gas or multi-component thermal fluid assisted SAGD (MCTF-SAGD) was designed, and this paper discusses the reservoir engineering design, the deployment of pilot well pairs and the field application performance prediction.
Selection of a Chemical EOR Strategy in a Heavy Oil Reservoir Using Laboratory Data and Reservoir Simulation
Authors: Fortenberry R. , Suniga P. , Mothersele S. , Delshad M. , Lashgari H. , Pope Gary A.
Published: May 2015

Chemical enhanced oil recovery (CEOR) of heavy oils is growing in volume and scope due to advances in the technology and field experience. This work describes a new methodology to select a CEOR strategy in a heavy oil reservoir when several viable options exist. We applied this methodology to the Pelican Lake field in Alberta.

We evaluated water flooding, polymer flooding, alkaline-surfactant-polymer (ASP) flooding, alkaline-co-solvent-polymer (ACP) flooding and polymer flooding followed by ASP flooding in laboratory tests. We executed new experiments including microemulsion phase behavior, polymer rheology and corefloods representing these various strategies. These experiments were designed to help understand the role of mobility control in chemical flooding of heavy oils. UTCHEM, the University of Texas Chemical Flooding Simulator, was used to model experimental results, and to scale them up in pilot simulations using heterogeneous geological models representative of Pelican Lake.

We report results for the selection of promising CEOR strategies for implementation in Pelican Lake based on the new laboratory experiments, reservoir simulations and our qualitative understanding of their various advantages and disadvantages. We present simulation results of a pilot using horizontal wells in a heterogeneous geological model representative of the reservoir. We simulated the various chemical EOR processes using the matched experimental data and evaluated them in terms of total oil production, time to completion and complexity. In-situ oil viscosity and operational injection limits were evaluated as crucial sensitivities. We make recommendations for CEOR implementation based on simulation study results and our understanding of relative process risks and costs.
Global Well Completion Reliability Databases and their Use in Well Design
Authors: Sparke Simon J.
Published: May 2015

Tullow Oil has been very successful exploring both onshore Kenya and Uganda and in deepwater Ghana, and as a result planning for major development projects got underway. In East Africa it is planned for hundreds of wells to be operated using artificial lift with waxy oil, deviated wells and sometimes quite shallow with reservoirs around 750 M. In Ghana well reliability is critical due to the prohibitive re-entry costs in the event of completion component failures operating in water depths up to 7,0 ft.

Therefore the need to benchmark well designs and component selection and plan the support mechanisms around realistic mean time to failure and other well operating risk factors is a crucial input process for the field development plans.

Today, the global well count is in the order of 2,000,000 wells and includes all well types from oil/gas producers, water/gas injectors to water disposal wells. Given the cost of drilling wells and the additional costs and risks involved in maintaining well stocks over the full well lifecycle, one would expect the oil and gas industry to think like other reliability focussed industries such as aircraft manufacturing / operating. Sharing data should be the norm especially as operators have a strong desire to maximise production by minimising the number of well interventions through the selection of the most suitable and reliable well equipment.

Logically when enquiring about equipment reliability, this should start with the equipment provider(s), however, they are understandably biased and not in a position to provide an objective and comparative answer as they are in competition with other equipment providers.

However, given this bias, an independently managed reliability database containing data for many hundreds of thousands of wells accessible for a nominal fee would have solved this problem. Unfortunately this was not the case in late 2013. What did exist were three databases run by two companies as JlP's whose software was did not reflect current technology and was not particularly user friendly. Further, the databases collectively held about 100,000 wells (roughly 5% of the global well stock) to cover onshore, offshore platform and subsea and well types from PCP, ESP, gas lift and natural producer and water injector.

At the time of writing this paper, the oil price was under $50/bbl, its lowest for many years, triggering an industry shake up that will question every dollar being spent on well operations and interventions. The key question that faced Tullow was, ‘what is the expected run life for ESP's so that a realistic economic forecast can be made on the work over frequency for the various fields’.

This paper discusses a two year journey to develop a global database, its outcomes and the benefits of the industry working together to provide one searchable database for the use of contributing industry stakeholders.
Assessing the potential of using water reclamation to improve the water environment and economy: scenario analysis of Tianjin, China
Authors: Xiang Nan , Xu Feng , Shi Min-Jun , Zhou Ding-Yang
Published: May 2015

Tianjin City in China is a typical area that suffers from a serious water resource shortage and pollution problems, and this situation has spurred the use of reclaimed water as an additional source of water and an efficient method of improving water quality. This study aims to assess the reclaimed water utilisation amount available and its potential impacts on the water environment and economy, and proposes applicable approaches to establish the optimal development for Tianjin. A water resources-environment-economic management model was constructed, which was accomplished by dynamic linear optimisation. Through scenario analysis, Tianjin's optimal reclaimed water recycle rate can reach 56%, with 475 × 106 tons of reclaimed water amount available (supporting 22% of the water supply), while bringing sufficient environmental and economic benefits, such as reducing 20% of water pollutants and maintaining 6.3% annual economic growth by 2020. This research also suggests that an integrated water management approach is preferable, including a proper introduction of technologies suited to the region's needs, a support system for construction, and control of water pollutant emission sources, especially in agriculture. The originally formulated water management system can be easily applied and extended to solve water issues, especially for water recycling.
Semi-symmetry of δ(2,2) Chen ideal submanifolds
Authors: Pantic Anica , Petrovic-Torgaseva Miroslava
Published: May 2015

In this paper we discuss ?(2,2) Chen ideal submanifolds M4 in the Euclidean
space E6, and we find the necessary and sufficient conditions under which
such a submanifold M4 is semi-symmetric, i.e. it satisfies the condition
R(X,Y)? R = 0.
Some inequalities on submanifolds in statistical manifolds of constant curvature
Authors: Aydin Muhittin , Mihai Adela , Mihai Ion
Published: May 2015

In this paper, we study the behaviour of submanifolds in statistical
manifolds of constant curvature. We investigate curvature properties of such
submanifolds. Some inequalities for submanifolds with any codimension and
hypersurfaces of statistical manifolds of constant curvature are also
established.