bluuebunny/crossref_metadata_2025 huggingface dataset:
Practical Experiences of Improvement of Oil Recovery for SZ Heavy Oil Reservoir in the Stage of High Water-cut
Authors: Su Yanchun , Liu Yingxian , Li Yanlai
Published: June 2012

More than 80% oil reservs is heavy oil in Bohai Bay of China.This paper describes the practice and research for comprehensive adjustment of SZ oil filed which is a large scale multi-layer sandstone heavy oil reservoir in China Offshore.In order to explore the potential of the reservoir, based on the fine geological studies, dynamic data of production and testing, we got water-cut contour of sub-layers by reservoir engineering method. Quantitative description of the remaining oil in the vertical and plane direction was gained by reservoir numerical simulation method, which could be the foundation for deployment of infilling wells and adjustment program of the oilfield. All the above were verified by the pilot well. Based on these studies, we designed infill wells between the edge and corner production wells and the the well network of the oilfield changed from nine-spot pattern to line drive well network. And in the comprehensive adjustment plan we designed 52 wells, the recovery of the oilfield will increase 7.8% compared to basic program.Combined with scaled corning data and the inversion of original resistivity, we established perforating program on the basis of fine numerical model and similar oilfield experiences. Water-cut of the new drilled wells were decreased, the potential productivity of them was fully released, and the effect of the water flooding was improved. Untill Dec 2011, 48 wells have been drilled, and the cumulative oil production of the new wells was about 174 × 104m3, the recovery is expected to be enhanced more than 10.4%.The production performance of the new wells shows that the direction of the adjustment for the heavy oilfield and the method for studying the remaining oil distribution are scientifical and reasonable. The research ideas during this comprehensive adjustment and the method for studying the distribution of remaining oil in the vertical and plane direction of the reservoir can be taken as a reference for similar oilfields, such as JZ and QHD oilfields in Bohai bay.
Laboratory Testing of Addition of Solvents to Steam to Improve SAGD Process
Authors: Ardali M. , Barrufet M. , Mamora D. D.
Published: June 2012

Steam Assisted gravity drainage (SAGD) is demonstrated as a proven technology to unlock heavy oil and bitumen in Canadian reservoirs. One of the long-term concerns with the SAGD process is high energy intensity and related environmental impacts. The addition of suitable hydrocarbon solvents to steam has long been regarded as the simplest and most effective method to increase SAGD performance. Higher oil recovery, accelerated oil production rate, reduced steam to oil ratio and generally more favorable economics is expected from the addition of potential hydrocarbon additives to steam. This paper summarizes experimental results of addition of potential solvents to steam in SAGD process. N-Hexane and n-heptane were co-injected with the steam and the experimental results were compared with pure steam injection. In addition, pure heated n-hexane was injected in one experiment to assess the performance of solvent-based processes. Experiments were conducted using a scaled two-dimensional physical model. Peace River Bitumen samples were used to conduct the experiments at 80 psia.

Experimental results were analyzed to determine the key variables involved in Solvent Assisted SAGD (SA-SAGD) processes. Solvent choice is not solely dependent on mobility improvement capability but also reservoir properties and operational conditions. Co-injection of suitable solvents with the steam led to accelerated oil production rate, higher oil recovery and lower energy to oil ratio. Solvent requirement for pure heated n-hexane injection was considerably high. The vaporized solvent chamber expansion was slow due to low heat content of the solvent and heat losses.
Physical Modeling of Solvent-Assisted SAGD
Authors: Khaledi Rahman , Beckman Mark , Pustanyk Karl , Mohan Aruna , Wattenbarger Chick , Dickson Jasper , Boone Thomas
Published: June 2012

Physical modeling of heavy oil recovery processes is a critical step in evaluating their technical feasibility. Results from physical modeling studies, in conjunction with simulation and analytical modeling, are key to technically justifying field trials and pilots. Proper scaling of reservoir model dimensions, reservoir properties and energy boundary conditions, operating condition monitoring and control, and production data analysis are very important aspects of physical model design and operation for evaluating the performance of a heavy oil recovery process. This paper describes physical modeling and performance evaluation of the Solvent-Assisted SAGD (SA-SAGD) process applied to Athabasca oil sand reservoirs with focus on process optimization under low operating pressure condition. The paper presents the design features of the physical model used for testing that ensures reliability and reproducibility of the experimental results. The results of laboratory testing are shown with emphasis on demonstrating the reliability and reproducibility of the test results.
Experimental Investigation of HLP Nanofluid Potential to Enhance Oil Recovery: A Mechanistic Approach
Authors: Shahrabadi Abbas , Bagherzadeh Hadi , Roustaei Abbas , Golghanddashti Hassan
Published: June 2012

Regarding the most reservoirs around the world are experiencing their second half of life, the need for an appropriate EOR method utilizing efficient new technologies gets more important. Nanotechnology is an advanced technology finding its place in EOR processes as it provides a high potential for oil and gas recovery.

In this study, a special type of polysilicon nanoparticle (HLP, Hydrophobic and Lipophilic Polysilicon) is investigated as an EOR agent during different water injection scenarios. The water-wet sandstone core samples are employed. Injection of HLP nanoparticle dispersed in a carrier fluid can improve oil recovery through two mechanisms: reduction of interfacial tension and wettability alteration. Reduction of interfacial tension improves pore-scale displacement efficiency. In addition, wettability alteration towards less water-wet condition provides an ideal wetting state increasing oil recovery. Three scenarios of HLP nanofluid injections are applied. First, the nanofluid is injected after waterflooding at ultimate oil saturation. Second, 3 porevolume water injection is applied after the sequence of water and HLP nanofluid injections. Third, HLP nanofluid is injected from beginning. HLP nanofluid application lowers the oil-water interfacial tension by a factor of ten as well as changing the contact angle from 123° to 99°indicating less water wet condition. The experienced oil recoveries and pressure drops during the experiments are reported for each scenario. In all scenarios, the most of oil recovered through the first injected pore volume. According to oil recoveries, nanofluid injection from the beginning can enhance oil production considerably in compare to the other ones. Moreover, pressure drop data indicate severe permeability impairment after three pore-volume injection of nanofluids. Experimentally, nanotechnology has proved its potential to enhance oil recovery however many aspects are still in progress to be known.
Influence of Nanomaterials in Oilwell Cement Hydration and Mechanical Properties
Authors: Santra Ashok , Boul Peter J. , Pang Xueyu
Published: June 2012

Nanotechnology encompasses a wide scope of disciplines and nanomaterials are now being used as commercially viable solutions to technical challenges in industries ranging from electronics to bio-medicine. Recently, the application of nanomaterials to solve problems in oilwell cementing has begun to be investigated by several different research groups in the oil and gas industry. The following uses of nanomaterials have been presented by several independent laboratories as possibilities in the oilwell cementing industry: (1) nanosilica and nanoalumina as potential accelerators; (2) nanomaterials including carbon nanotubes (CNTs) with high aspect ratio to enhance mechanical properties; (3) nanomaterials to reduce permeability/porosity; and (4) nanomaterials to increase thermal and/or electrical conductivity.

In this paper, a review of the aforementioned application concepts is presented with a focus on understanding the role of multiwall CNTs (MWNTs), nanosilica, and nanoalumina in oilwell cement hydration chemistry. The influence of the integration of MWNTs into oilwell cement on the physical properties of cement is discussed. Results from an isothermal microcalorimetric study are presented to help understand the difference between the mode of acceleration of a typical cement accelerator, like CaCl2, compared to nanosilica and/or nanoalumina.
The Viscosity of Silica Nanoparticle Dispersions in Permeable Media
Authors: Metin Cigdem Omurlu , Bonnecaze Roger T. , Nguyen Quoc P.
Published: June 2012

The potential application of nanoparticle dispersions as formation stimulation agents, contrast agents or simply as tracers in upstream oil and gas industry requires knowledge of the flow properties of these nanoparticles. The modeling of nanoparticle transport in hydrocarbon reservoirs requires a comprehensive understanding of the rheological behavior of these nanofluids. Silica nanoparticles have been commonly used because of their low-cost fabrication and cost-effective surface modification. The aqueous silica nanoparticle dispersions show Newtonian behavior under steady shear measurements controlled by a rheometer as discussed by Metin et al. [1]. The viscosity of nanoparticle dispersions depends strongly on the particle concentration and that this correlation can be depicted by a unified rheological model [1]. In addition, during flow in permeable media, the variation of shear associated with complex pore morphology and the interactions between the nanoparticles and tortuous flow channels can affect the viscosity of nanoparticle dispersion. The latter is particularly important where the concentration of nanoparticles in dispersion may change because of nanoparticle adsorption on mineral/fluid and oil/water interfaces or by mechanical trapping of nanoparticles. In this paper, the flow of silica nanoparticle dispersions through different permeable media is investigated. The rheological behaviors of the dispersions are compared with those determined using a rheometer. We established a correlation between the nanoparticle concentration and dispersion viscosity in porous media for various nanoparticle sizes. The effects of pore structure and shear rate are also studied. We have confirmed that the concept of effective maximum packing fraction can be applied to describe the viscosity of aqueous nanoparticle dispersions in both bulk flow and flow in porous media with high permeability and regular pore structures but not at low permeability because of mechanical trapping. Our work provides new insight to engineering nanoparticle rheology for subsurface applications.
High Strength Nanostructured Materials and Their Oil Field Applications
Authors: Zhang Zhihui , Xu Zhiyue , Salinas Bobby
Published: June 2012

High strength Al nanostructured materials have attracted increasing attention for weight critical and high reliability completion tools applications in the oil and gas industry. The novel nanostructured materials have demonstrated ultrahigh specific strength (i.e. ∼3 times of steel), enhanced specific stiffness, and great potential in tailoring the desirable dynamic and corrosion properties.

Traditional light weight material for ball or plug applications are prone to early yielding or shape changes. The yield strength of conventional aluminum alloys is usually less than 400 MPa. Nanotechnology can be effectively employed to enhance the mechanical properties and other desirable properties through engineering the material microstructure. Mechanical milling is used as approach for synthesis of nanostructured powders by conducting severe cyclic plastic deformation in powders and thereby promoting the formation of nanostructures. Our results showed that ultrahigh strength up to 1000 MPa can be achieved for Al-based nano-composites by controlling the distribution of the micro-and nanoparticles in the matrix. And corrosion behavior of the material can be controlled by tuning the matrix grain size from 100 to 500 nm depending on the processing parameters. The nanostructured materials also demonstrated excellent high strain rate ductility while maintaining its high strength. Examples of oil field applications of the nanostructured materials will be presented.
Lessons Learned from Using New Chemical Recipe for Acid Stimulation in Water Disposal Wells (Al-Khafji Field)
Authors: Al-Dhafeeri Abdullah M. , Al-Dhaferi Yousef R. , Ahmed Al-Sadah Ahmed Alawi
Published: June 2012

Acid treatments for dolomite formation with low permeability differ from that applied for calcite rock. Unlike limestone acidizing where HCl reacts with limestone in rapid reaction rate to generate reaction products soluble in water. In Some cases, injectivity well can not effectively improve in dolomite formation with low permeability using conventional 15 wt% HCl acid. In addition, formation damage due to drilling or workover operations can not be removed. Therefore, the process of treating dolomite for injectivitiy improvement may consider a serious issue for acid stimulation. The challenges of dolomite acidizing are to optimize damage removal while maximizing rock permeability with wormhole occurrences.

Well DW-4 drilled and completed as horizontal open hole wastewater disposal wells for excess water production from offshore oil wells in Al-Khafji Field. This well is used to dispose the un-wanted co-produced water which shows injectivity decline with time due to sand plugging and oil content droplet.

Several acid stimulation treatments were conducted on subject well with low rate of success due to not considering the dolomite reaction rate and the chemical volume to be used. A simple previous treatment review was conducted to select the best chemical recipe and treatment volume for injectivity improvement. As a result of conducting new chemicals recipe with optimum treatment volume, a major improvement in well injectivity with formation damage removal was obtained. This paper demonstrated new design methodology with extensive field study to address the challenges and the best future operation practices for acid stimulation. It included a pre-flush of mutual solvents, then bullheading stage of 20 wt% HCl with intensifier to accelerate the chemical reaction with dolomite rock.

A carefully designed train of treatment fluids was applied to remove formation damage induced by drilling and injection fluids. Injectivity tests before and after each step of the treatment was recorded and evaluated. Proper design and execution of the stimulation treatment almost doubled the well injectivity index. Challenges, fluid selection, design criteria, field treatment, lessons learned, and results of the acid treatments were discussed in this paper.
Downhole Heavy Oil Characterization Using 3D NMR and Modern Dielectric Logs
Authors: Al-Yaarubi Azzan H. , Al-Bulushi Nabil , Al-Mjeni Rifaat A.
Published: June 2012

Due to a surge in oil demand over the past years and its impact on prices, major heavy oil accumulations are gaining special attention in the Middle East. Knowledge of the fluid characteristics is critical to determine a suitable recovery process for heavy oil reservoirs. Oil viscosity is the property that most affects producibility and ultimate recovery in these settings, but it is the most difficult property to determine. This is due to the challenges associated with obtaining representative oil samples in increasingly heavy oil reservoirs. Additionally, the oil viscosities in these reservoirs exhibit large variations within the same formation. Hence, downhole in-situ measurements are key in establishing viscosities and their variation within the reservoir.

Current practice in heavy oil accumulation is to extract oil samples through crushing of cores at surface, or sampling through changing the temperature of the near wellbore in the hope that the fluid will flow. These techniques provide viscosity ranges that help in uncertainty testing of various recovery processes but are only point-data measurements. Nuclear magnetic resonance (NMR) logging is also used to determine in-situ oil viscosity accurately in conventional light oil reservoirs. However, this technique has limitations in heavy oil settings because the extremely fast relaxivity of the heavy oil components results in very short transverse or relaxation time (T2) values that are not detectable by the NMR tool. The short T2 time also means that the heavy oil and bound-water signals, overlap resulting in an ambiguous oil signal.

A novel technique combines data from 3D NMR and dielectric dispersion tools to determine in-situ oil viscosity. This was based on recently published NMR viscosity correlations. The primary output from the dielectric tool is the total water volume. Using this output combined with the 3D NMR data makes it possible to accurately derive bound-water, free-water, and oil volumes. These are necessary inputs into NMR-based viscosity correlations. This technique yielded continuous logs of heavy oil viscosities within the same viscosity range as measurements obtained from the core data.
Single-Well SAGD Field Installation and Functionality Trials
Authors: Hocking Grant , Cavender Travis , Person John , Hunter Tim
Published: June 2012

A vertical single-well steam-assisted gravity drainage (SAGD) injector/producer is proposed that consists of six vertical propped planes installed at varying azimuths throughout the pay thickness to minimize geological heterogeneities on system performance. Steam is injected at the top of the pay and liquids are extracted at the bottom. The well operates immediately in SAGD mode and is highly efficient because of the immediate drainage available from the propped vertical planes, the full gravity drainage height at startup, and a favorable steam pressure gradient. A field trial is presented of the installation of multi-azimuth vertical propped planes from two expanded split-casing sections in a sandy silt formation. Each casing section contained six vertical propped planes at multiple azimuths that were coalesced by pore-pressure relief between the casing sections. Downhole expansion and splitting of the 9 5/8-in. casing and cement quantified formation stiffness and strength, while downhole photographs and packer impressions showed the split casing in the locked-open position. Each wing was stimulated independently of the other wings with 12/20-mesh proppant injected using a highly crosslinked gel through a specialized treatment tool. Real-time active resistivity monitoring quantified the injected plane geometry from both subsurface and surface resistivity receivers. Hydraulic pulse interference tests quantified the hydraulic vertical connectivity of the vertical propped planes. The field trials showed conclusively that multiple vertical propped planes on various azimuths can be constructed from a single wellbore and the planes coalesced between casing sections spaced along the wellbore. The field trials demonstrated the functionality of the expanded casing and stimulation tools and showed that the vertical permeable propped planes could be constructed on azimuth with high in-placed permeability. The geometry of the injected planes was recorded in real-time using the active resistivity method. Following completion of the stimulations, surface excavations showed two of the vertical planes on azimuth with the multi-azimuth casing dilation planes. Following this successful field trial, heavy-oil and bitumen steaming trials are planned.
Field Scale Simulation of Cyclic Solvent Injection (CSI)
Authors: Chang Jeannine , Ivory John
Published: June 2012

Only 5 – 10% of the oil in Lloydminster heavy oil reservoirs is recovered during cold production with sand (CHOPS). Cyclic solvent injection (CSI) is the most promising post-CHOPS follow-up process. In CSI, a solvent mixture (e.g. methane-propane) is injected and allowed to soak into the reservoir before production begins (Figure 1). CSI has been focused on heavy oil recovery from post-CHOPS reservoirs that are too thin for an economic steam-based process. It has been piloted by NEXEN and by Husky and was a fundamental part of the $40 million Joint Implementation of Vapour Extraction (JIVE) solvent pilot program that ran from 2006–2010.

This paper describes field scale simulations of CSI performed with a comprehensive numerical model that uses "mass transfer" rate equations to represent non-equilibrium solvent solubility behaviour i.e. there is a delay before the solvent reaches its equilibrium solubility in oil. The model contains mechanisms to consider foaming or to ignore it depending on the field behaviour. It has been used to match laboratory experiments, design CSI operating strategies, and to interpret CSI field pilot results.

The paper summarizes the impact on simulation predictions of post-CHOPS reservoir characterizations where the wormhole region was represented by one of the following five configurations: (1) an effective high permeability zone, (2) a dual permeability zone, (3) a dilated zone around the well, (4) wormholes (20 cm diameter spokes) extending from the well without branching, (5) wormholes extending from the well with branching from the main wormholes,. The different post-CHOPS configurations lead to dramatically different reservoir access for solvent and to different predictions of CSI performance.

The impacts of grid size, upscaling, well inflow parameter, solvent dissolution and exsolution rate constants, and injection strategy were examined. The assumption of instant equilibrium solubility resulted in a 23% reduction in oil production compared to when a delay in solvent dissolution and exsolution was allowed for. Increasing the grid block size by a factor of 9 reduced the predicted oil production five-fold. Assuming isothermal behaviour in the simulations decreased predicted oil production by 17%.
Application of Droplet Flow in Alkaline Flooding to Improve Sweep Efficiency in Heavy Oil Reservoirs
Authors: Pei H. H. , Zhang G. C. , Ge J. J. , Ding L. , Ma C. , Shen J. W.
Published: June 2012

This study presented the results of a laboratory study to investigating a method to improve sweep efficiency by application of droplet flow in alkaline flooding in heavy oil reservoirs. This included micromodel flooding tests, sandpack flooding experiments and 3D physical model study. The glass-etching micromodel tests show that the injected alkaline solution can penetrate into the oil phase and create some discontinuous water droplet inside the oil phase, and finally forms droplet flow phenomenon. Depending on the high viscosity and Jamin effect, the droplet flow tends to lower the mobility of the injected water and lead to the improvement of sweep efficiency. Droplet flow phenomenon is more obvious with the alkaline concentration increasing, and resulting in a greater improvement in sweep efficiency. A series of sandpack floods were conducted using 325 mPa·s, 2000 mPa·s, and 3950 mPa·s heavy oils to assess the effectiveness of droplet flow in alkaline flooding for enhanced heavy oil recovery. The sandpack flood results demonstrate the considerable potential for improved heavy oil recovery by alkaline flooding, and moreover, the incremental oil recovery and pressure drop have been found to increase as the alkaline concentration increases. The result obtained in 3D physical model study indicates that the sweep area can be greatly improved by the formation of droplet flow in alkaline flooding. The above results demonstrate the mechanism of droplet flow in alkaline flooding to improve sweep efficiency is the dominant mechanism for enhanced heavy oil recovery.
Determination of Limits to Production in THAI
Authors: Greaves M. , Dong L. L. , Rigby S. P.
Published: June 2012

The operational production period in Toe-to-Heel Air Injection (THAI) has been investigated via numerical simulation of a field scale section of the Conklin THAI pilot in the Athabasca Oil Sands. THAI is an advanced horizontal well development of the in situ combustion process for heavy oil recovery. It operates as a ‘short-distance’ displacement process, and is being applied to bitumen and heavy oil reservoirs.

Breakthrough of oxygen into the production well is predicted to occur after 10.8 years of oil production. This occurs during the declining oil rate period, which follows a sustained period of constant rate production. Prior to oil rate decline, the oil recovery factor was 63 %. High combustion temperatures aid continued expansion of the steam bank, maximizing oil recovery. Economic and also safety factors determine the ultimate decision point, concerning termination of operations. On the one hand, maximum oil recovery is determined by longer operation time, but this is also influenced by safety considerations, principally, the approach to oxygen breakthrough. Terminating the process early maximises the financial rate of return, but at the expense of total oil recovery. Reduction in the oil price is probably the most significant factor affecting profitability, but this also depends on timing and degree of financial risk.
Wellbore Bitumen Treatment: Mitigation of the Adhesive Properties of Oil Sands during Drilling Operations – Development and Field Trial
Authors: Livanec Philip W. , Perez Greg P.
Published: June 2012

Mitigation of bitumen and asphaltene accretion to the drillstring and other drilling components has become an important task due to the increasing production of oil sands and heavy oil deposits. When drilling through oil sands or encountering a bituminous zone, numerous problems can occur due to the extreme adhesive nature of the bitumen. Drillstrings and other tubulars can become coated, causing stuck pipe and undesired nonproductive time (NPT). Surface equipment such as shaker screens, can become fouled, resulting in poor drilling fluid properties. Common methods to counter the adhesive nature of bitumen have involved solvation of the bitumen into the drilling fluid. However, these methods not only contaminate the drilling fluid (resulting in disposal concerns), but can also negatively affect the fluid's properties, such as rheology.

This field trial utilizes a water-based mud and examines the effectiveness of a new polymer additive to mitigate the adhesive nature of bitumen, thereby preventing the occurrence of wellbore accretion. The bituminous cuttings are rendered non-adhesive, transported by the drilling fluid to the surface, and separated by conventional solids control equipment. In this fashion, the drilling fluid properties are not altered, and the water-based mud can be disposed of without the environmental issues of a contaminated fluid. Field trials and lab results have shown that small additions of this bitumen stabilization polymer to water-based drilling fluid renders the bitumen non-adhesive. Field trials have been completed in northern Canada and show extremely positive results with this polymer additive. It was shown that when the tar sands interact with the polymer additive, the tar becomes non-adhesive, and remains non-adhesive following contact with aqueous solutions. By preventing the bitumen from solvating or dispersing into the drilling fluid, the bituminous cuttings can easily be surface-separated. Torque and drag issues commonly seen while drilling through oil sands were also alleviated with use of this polymer additive.
The Importance of PVT to the Steam Solvent Process
Authors: Fan Shuanshi , Li Sijia , Xin Hua
Published: June 2012

Steam based thermal processes are major technologies for bitumen and heavy oil recovery. They are energy intensive, high water demand and huge CO2 emission. When such technologies are applied to the reservoir with thief zones, the economics are even worse. In order to increase the efficiency, people are trying to add solvent into steam to reduce the operation pressure and temperature so the economics. The mechanism of adding solvent into is further reducing the viscosity of bitumen or heavy oil an addition to thermal effects. That means the solvent should be dissolved into oil as soon as they meet each other at the interface. The boiling point of the solvent should be near that of steam. When it is to far from steam, it stays either liquid being produced without reacting with oil or gas stopping the heat exchange of steam. In this paper, PVT of some pure and commercial solvents is reviewed and potential operation pressure and temperature are discussed. This can help engineers to select solvent and design the process properly.
A Quarter Century of Progress in the Application of CO2 Immiscible EOR Project in Bati Raman Heavy Oil Field in Turkey
Authors: Sahin Secaeddin , Kalfa Ulker , Celebioglu Demet , Duygu Ersan , Lahna Hakki
Published: June 2012

The Bati Raman field is the largest oil field in Turkey containing approximately 1.85 billion barrels of initial oil in place at an average depth of 4300 ft. The oil is heavy (12° API) with high viscosity and low solution gas. Primary recovery between 1961 and 1986 was less than 2% of OOIP.

The commercial CO2-EOR project began in 1986 and is still active. With the implementation of the CO2 flood, the recovery is expected to potentially reach up to 10% of OOIP.

The reservoir rock is naturally fractured carbonate where the heterogeneities and the unfavorable mobility ratio of CO2 and crude caused inefficient sweep. The solubility of CO2 in the oil, which is highly sensitive to reservoir operating pressure, was a significant factor for the success of the CO2 flood. Currently, the injected agent is increasingly bypassing the remaining oil and the production is curtailed by excessive high gas/oil ratio (GOR) severely jeopardizing recovery. These conditions prompted the use of applications of the conformance-improvement systems in the wells in western part of the field.

Successful applications of fracture plugging polymer gel system intended for the conformance improvement were carried out in the years of 2002 and 2004. Also, to improve the recovery by a better sweep (or displacement), a chemically augmented water injection process was proposed in the areas having relatively lower reservoir pressure. Chemicals were tested for wettability alteration and IFT reduction to select the best performing ones. After an economic analysis, a field trial of the water alternating gas (WAG) injection process with caustic was put into progress in 2010.

Optimized application cases were determined by tuning the total gas injection rates of the field, proration of the individual well rates according to the GOR, investigation of infill drilling, and alteration of the gas injection pattern, based on the results of the simulations carried out in different time frames of the project history.

The Bati Raman immiscible CO2 injection project has been acknowledged as one of the most unique and successful enhanced oil recovery (EOR) applications in the history of fractured heavy-oil carbonate reservoirs. This paper presents a comprehensive overview of this project after a quarter century of experience.
Study of Sharp Drop in Production Rates of Horizontal Wells in Unconsolidated Rock of Heavy Oil Reservoir
Authors: Ivantsov N. , Stepanov S.
Published: June 2012

This article describes the results of a theoretical and numerical study of the problem of a sharp drop in production rates of horizontal wells in one of Western Siberia fields represented by reservoirs consisting of poorly consolidated rock and saturated with heavy oil. The under gas cap oil rim is developed by depletion by horizontal wells. The reduction of the production rates is analyzed from different perspectives among which the most appropriate idea is elastoplastic deformation of the rock with its subsequent destruction in the bottomhole zone. Based on the analysis of the stress-strain state and theoretically justified rock ultimate strength, it is shown that actual bottomhole pressures lead to brittle fracture of the rock and, as a result of related processes, to particles movement and sharp increase in the skin factor.
The Challenges in Processing Heavy Oil
Authors: Georgie Wally , Smith Colin
Published: June 2012

There are numerous flow assurance and processing challenges associated with the production of heavy oil. These challenges are generally addressed in the early stage of the development and include; sizing of separators, internal design of the vessels, the process vessel configuration and the optimum means of handling solids and water. A critical aspect of the design is the accuracy and the reliability of the fluid characterization data. Numerous operators can attest to the difficulties in processing heavy oil and many make attempts to minimize the impact of these issues in the design stage. However, there are critical factors associated with produced fluid characterization data that are regularly either overlooked or misinterpreted. It is the importance of this data reliability and accurate interpretation that is the subject of this paper.

The high viscosity and low gravity of heavy oil is usually the principle concern of the design team in addressing process components and operational practices. However, there are numerous horror stories associated with flow assurance issues that should have been taken into consideration during detailed design. The impact of asphaltenes, paraffin, naphthenates, inorganic scale deposition and emulsion stability are a few of the more common challenges that can, and should, be addressed prior to detailed design. The impact of these constituents on processing and operations can make or break the economics of the development, particularly when taking into account the long-term OPEX associated with chemical treatment cost if these constituents are not adequately addressed.

In addition, brown field development of heavy oil and the subsequent processing through an existing infrastructure will create other challenges, especially if the existing production infrastructure is designed to handle mid and high API gravity crude.

By following some fairly rigorous, but necessary, guidelines on data accumulation and interpretation most if not all of these problems can adequately be addressed during detailed design and the development of operating procedures. Therefore a holistic approach in assessing the design of these facilities will be crucial to maintaining a low CAPEX and OPEX for processing heavy oil effectively. This paper aims to outline the different aspects associated with these challenges and will cover design, operation, monitoring and, where relevant, upgrades and retrofit issues.
Flow Loop for X-Ray CT Imaging of Sand Transport
Authors: London M. , Cameron S. , Pierce G.
Published: June 2012

Two closed circuit flow loops have been constructed for X-ray CT imaging of multiphase flows. A 3rd generation helical scanner provides 3D images with a voxel size as small as 0.35×0.35×0.30mm. By "folding" the loops, flows have been imaged over a 16m section of 3.8 cm (1-1/2") pipe. In future, larger bores could be accommodated with a shorter overall length, dictated by the aperture and weight limit of the scanner.

Sand slurry flows have been imaged in both laminar and turbulent regimes (using silicone oil and water, respectively) over a range of velocities reflective of typical in situ pressure gradients. Flowing sand concentrations up to 20% by volume were achieved by adjusting the total sand content in the loop.

With proper calibration the CT images provide detailed, quantitative measures of sand concentration and, indirectly, the partitioning between moving and settled regions of the flow. The flowing density profiles vary significantly with the sand content and flow velocity, indicative of changing sand transport mechanisms. Fluctuations over the observable length of the loop show evidence of settling overlaid on the flow-induced resuspension. The effects of the end loops on both aspects of sand transport are considered.
Implementing Lean Manufacturing Principles in New Well Construction
Authors: Charles Steven R. , Deutman Robert , Gold David K.
Published: June 2012

The Aera Energy LLC (Aera) Development Team has drilled and completed, each year since 2000, about 1,000 oil producers and water/steam injectors, and constructed the associated surface facilities. Such a high activity level, which involves some 800 contractors and hundreds of pieces of mobile oilfield equipment, leads to unsurpassed congestion and logistical complexity, requiring a different approach from traditional planning and execution methodologies. In 2001, Aera turned to the manufacturing industry for ideas. The company realized that drilling and constructing a well is not just a step in delivering a commodity; it is manufacturing a new well. The decision was made to implement Lean principles in the development process. Some of the Lean principles that were adopted were: moving from large batches of wells to near single-piece flow; just-in-time execution of planning and implementation activities; relentless focus on continuous improvement through mapping of work processes and eliminating the identified waste; designing and constructing oilfield equipment that is right-sized for the application needed; and creation of a very transparent system of visual tools that shows the status of key indicators at any point in time. The transition to Lean has paid off. The desired high release rate of wells has been maintained despite significant oil price volatility. The safety performance of the Aera Development Team and its contractors improved continuously and the injury frequency was reduced by a factor of 10. The drilling and completion cost (on a per-foot basis) for the most common well type was held flat in nominal terms between 1997 and 2011, while industry costs more than doubled over the same period. In 2011, Aera was the first oil company to receive the Manufacturing Excellence Award from the Association for Manufacturing Excellence. The award recognizes "demonstrated excellence in their operations" and has a primary focus "to acknowledge continuous improvement, best practices, creativity, and innovation." This paper describes the Lean journey including the culture change that was needed, the obstacles that had to be overcome, examples of Lean implementation (e.g., tools, processes, results), and the critical success factors to successfully implement Lean in new well construction.
Elimination of Surface Casing Vent Flow and Gas Migration in the Lloydminster Area
Authors: Macedo Kevin G. , Schneider Jason W. , Sylvestre Chuck J. , Masroor Qasim
Published: June 2012

There are many areas in the Western Canadian Sedimentary Basin that present challenges with surface casing vent flows (SCVFs). Substantial resources have been invested in understanding the causes of these SCVFs, developing remediation processes for wells impacted by SCVFs and creating products to prevent SCVFs from occurring. Despite these efforts, SCVFs remain an issue in the industry. The first priority of the energy company and service company is to operate in a safe manner with high regard for the environment. A secondary goal is to be cost efficient to maximize production. In order to satisfy these goals and priorities, working together to understand the challenges becomes critical. A clear understanding of the challenges provides an opportunity for the service company to tailor cement blend performance with the goal of eliminating the presence of SCVFs and reducing the costs associated with the remediation process.

This paper presents a case study in the Celtic field, located approximately 80 kms northeast of Lloydminster, Saskatchewan, Canada. A higher frequency of SCVFs was observed in the wells when increased bottom circulating temperatures, influenced by a nearby active steam chamber, were reported while drilling. At the elevated temperatures, cement blend modifications were made to allow for adequate placement with the new wellbore parameters. The cement blend underwent a review and optimization process with respect to the new wellbore parameters.

Findings showed that a substantial difference between the circulating and gas formation temperatures created ideal conditions for SCVFs to occur. The prolonged setting of the cement at low temperatures was believed to be the main challenge to overcome. A unique cement additive was used to accelerate the setting of the slurry at relatively low temperatures while ensuring it would still be pumpable in a high temperature environment. After incorporating the new additive into the cement blend, the operating company immediately saw an elimination of the SCVF in subsequent wells.

This paper will review the steps taken to reduce and eliminate SCVF issues in the Celtic area, some parameters and characteristics of a well that impact SCVF, and steps that can be taken in the cement blend design to mitigate SCVF issues.
Numerical Simulation Study on Gravel-Packing Layer Damage by Integration of Innovative Experimental Observations
Authors: Li Y. , Li M. , Qin G. , Wu J. , Wang W.
Published: June 2012

Sand control is vitally important to operation integrity in producing heavy-oil from unconsolidated reservoirs. Among various sand exclusion technologies, the open-hole gravel pack (OHGP) has been widely used in horizontal well completions. It is thus critical to quantitatively evaluate gravel packing layer damage and understand its mechanisms.

In this paper, we propose an integrated study to quantitatively evaluate gravel packing damage based on the real-world scenarios and, thus provided design criteria for gavel packing. We have designed an experimental system that can measure the core pressure at multiple points in gravel layers at high pressure condition as well as track sand migration. Preliminary results indicate that pore structure of gravel packing layer changes and the permeability decreases with sand migration and plugging. Sand volume fraction, fluid viscosity, and sand radius are the main factors that cause gravel packing layer damage.

We have developed a numerical model based on experimental observations. The numerical model considers liquid-solid fluid flow processes, sand migration and plugging in gravel layer. Numerical simulation studies are then performed on the gravel damage at different sand volume fraction, fluid viscosity, and sand radius. The simulated results are in agreement with experimental results. The numerical simulation studies on real-world scenarios are under investigation and we will report the numerical results in later reports.
Post SAGD In-Situ Combustion: Potentials and Challenges
Authors: Javad S. , Oskouei P. , Moore R. G. , Maini B. , Mehta S. A.
Published: June 2012

In Situ Combustion, ISC, is a process with strong potential to compliment Steam Assisted Gravity Drainage by extending the economic life of the SAGD pattern and hence improving the ultimate recovery. Implementing In-Situ Combustion, as a follow-up process to SAGD can improve recovery from the pattern by displacing residual oil from the steam chamber and more importantly by recovering oil from the wedge zones. Theoretically the temperature and residual oil saturation within the SAGD chamber are high enough to initiate and sustain the combustion process by switching from steam to air injection; however laboratory investigations of the hybrid process have shown that the in situ combustion behavior within the steam zone has some special features which must be considered.

Injection of air into the SAGD injection well is the desired option from an economic view point, however laboratory tests showed that the combustion zone tended to be more stable when air was injected at a location higher up in the chamber. This behavior relates to the fact that the combustion reactions were primarily occurring within the vapor phase, hence gravity plays a dominant role controlling the distribution of air flux within the chamber as well as the drainage of oil and water out of the combustion zone. Laboratory tests also confirmed the importance of promoting air flux across the walls of the original steamed chamber.
Experimental Study of the Mechanisms in Heavy Oil Waterflooding Using Etched Glass Micromodel
Authors: Mei S. , Bryan J. , Kantzas A.
Published: June 2012

In western Canada, there have been more than 300 heavy oil waterflooding projects. Most of these projects displayed good economical and efficient variability even though they were operated in marginal pools. Although waterflooding of heavy oil has almost 50 years history, its mechanisms, especially in the situation of high oil water viscosity ratio, are still not well understood. In the situation of high viscosity ratio, fractional flow theory does not work because of severe water fingering and other mechanisms that are different from conventional waterfloods. The operation strategies of heavy oil waterflooding, such as water injection rate, injection pressure and VRR, are still under controversy.

In a water-wet environment, waterflooding (water displacing oil) represents a process of water imbibition. In this paper, the water imbibition mechanisms and their effects on the heavy oil recovery are studied using a water-wet micromodel. The effects of time, viscosity ratio and water injection rate on the imbibition rate are also studied. The imbibition rate of water was found to be proportional to the reciprocal of the square root of time, and inversely related to oil viscosity. The effects of injection rate on imbibition rate are complicated. At low injection rates, waterflooding becomes more efficient, and significant volume of oil is produced discontinuously. Images of the imbibition process were recorded and analyzed from visual micromodel studies. Water broke through quickly because of water fingering, and a considerable portion of recovery comes from post-breakthrough production of oil, under high water cuts. In the cases of low rate water injection, water imbibed into the original oil region perpendicularly to the water channel. In this stage, capillary imbibition was a key factor. Water film thickening and snap-off were the two main mechanisms that made water imbibition work. Emulsification was also another important mechanism observed, with W/O emulsions primarily being formed.