bluuebunny/crossref_metadata_2025 huggingface dataset:
SAGD Development Strategy for Concurrent Production of Two Vertically Stacked Clastic Reservoirs
Authors: Jiang Qi , Nugent Daniel , Meyer Kelli
Published: December 2011

The southwest portion of the proposed Taiga project has two vertically stacked bitumen-filled Cretaceous sandstone reservoirs in the Cold Lake area of NW Alberta, Canada. The shallower Lower Grand Rapids Formation is separated from the Clearwater Formation by the transgressive Clearwater. SAGD (steam assisted gravity drainage) is planned for producing both formations simultaneously.

The Lower Grand Rapids Formation differs from the Clearwater Formation in initial reservoir pressure, oil viscosity and fluid distribution. Therefore, this will require individual well placement and operational strategies for each reservoir. The sequence of development for the two reservoirs will not only affect the pad facility design and operation strategy but will also affect the drilling operations. There is a high likelihood of drilling into the areas conductively heated by prior proximal SAGD operations if two formations are developed in a sequential order. This increases drilling risks and costs. Simultaneous SAGD operations within both the Lower Grand Rapids and Clearwater Formations can be used to minimize the complexities associated with well drilling and completions, and to reduce the initial number of surface pads as both formations can be accessed from the wells drilled from the same surface location.

This paper presents the results from both reservoir simulation and geo-mechanical modeling based on geological and reservoir characteristics of these reservoirs. The surface heave due to dual zone thermal operations is also predicted based on the results from geo-mechanical modeling. These studies have led to an optimal design of pads and operating parameters for concurrent production of the two reservoirs which is technically, environmentally and economically efficient.
Restimulation of Wells using Biodegradable Particulates as Temporary Diverting Agents
Authors: Allison Dave , Curry Shawn , Todd Brad
Published: December 2011

During the life of producing wells, there comes a time when the well approaches its economic viability as a producing well. If the reservoir potential is sufficient to support the expenditure, many wells are candidates for recompletion, reperforation, or restimulation. This type of focus on the Barnett shale began in the late 1990s. Drilling activity dramatically increased during the ensuing years and now there are more than 14,000 wells that have been drilled, most of which are producing wells. A lot of these wells are potential candidates for restimulation (refrac) because their production rates have declined but still have significant reservoir potential. The completion techniques deployed in the Barnett evolved over time to where many wells have dozensof perforation clusters and hundreds of individual perforations. Generally, refracsare ineffectual unless the perforations can be temporarily isolated so that the energy of the subsequent fracturing treatment can be focused on individual portions of the reservoir. Additionally, refrac candidate wells often contain challenging wellbore environments that further complicate the ability to successfully refrac the wells. The use of biodegradable particulates to facilitate the temporary diversion and concentration of frac energy has increased the success of restimulation.

This paper discusses the recent development of techniques and materials being used in refracturing operations. Included are discussions of laboratory results of new and novel materials, along with case histories of refrac wells demonstrating application of such materials and techniques.
Evaluation of Long-Term Performance of Oil Wells in Elm Coulee Field
Authors: Kurtoglu B. , Cox S. A. , Kazemi H.
Published: December 2011

Unconventional oil reservoirs, such as Bakken, have gained considerable interest in recent years because they have become a great resource to produce oil and gas to meet the energy needs of North America. Performance prediction from these tight reservoirs is a challenge because of the complexity of reservoir flow, well completion, and fracture stimulation techniques. Elm Coulee field, in Bakken, is an example of such unconventional reservoirs and is located in Richland County, Montana. The field was drilled using both vertical and horizontal wells, but in recent years the use of horizontal wells has become the standard practice. The objectives of this study were: (1) evaluate the long-term (7 to 10 years) performance of horizontal wells in Montana Elm Coulee, (2) develop a better understanding of how to predict the long-term performance of younger Bakken fields in North Dakota based on the Elm Coulee experience.

Arps hyperbolic decline curve analysis was used as the main forecasting approach. In Arps analysis, q(t) = qi (1 + bDit)−1/b, where q is the flow rate, D is the decline rate, and b is the decline exponent. It will be demonstrated that forecasts using a constant b overpredicts well performance. To match the long-term performance of Elm Coulee wells, the numerical value of b had to be decreased with time.

Analytical approaches (log-log type-curve diagnostic plots and the Fetkovich log-log normalized plot) were also used to decipher the flow regimes, and to determine the varying decline rate from long-term producing wells in Elm Coulee Field. In addition to analytical modeling, numerical modeling was also used because it is more comprehensive in utilizing a larger set of reservoir parameters such as reservoir heterogeneity variations. This is very useful in transferring what we learned from the long-term performance of Elm Coulee Montana wells to the short-term performance of wells in North Dakota by addressing both geology and reservoir property differences between these fields.
Modeling the Effect of Permeability Anisotropy on the Steam-Assisted Gravity Drainage (SAGD) Process
Authors: Azom Prince N. , Srinivasan Sanjay
Published: December 2011

The SAGD process utilizes horizontal wells hence permeability anisotropy can play a very strong role in recovery. In fact, it has been well documented that poor vertical permeability kills the SAGD process because the steam chamber will not grow properly. Several authors have attempted to model this phenomenom by using time-independent averaging (e.g. harmonic, geometric averaging etc.) methods only to discover the inadequacy of such an approach as several field implementations reveal a definite time component to this effect. Consequently most studies on the effect of anisotropy during SAGD have involved only commercial simulators. However, there exists a need to describe this phenomenon quantitatively prior to any numerical simulation and delineating conditions where it can be considered important or not.

Isotropy of permeability can be geometrically represented as a sphere (or circle in 2D) where the permeability radii are the same in all directions. Anisotropy can be represented as an ellipsoid (or ellipse in 2D) with varying permeability radii in different directions and the principal axes representing principal permeability directions. In this work, we assume that the principal axes point in the vertical and horizontal directions. We will show that the SAGD process has a unique geometry that allows a meaningful mapping of the steam chamber wall to the coordinate frame of such an ellipsoid. We will then use this transformation to incorporate permeability anisotropy within the framework of Butler type models. This will be done in dimensionless space and the results obtained can be used as type curves for correcting any isotropic SAGD model for anisotropic effects.

Our results show that the effect of anisotropy is time dependent (generally obeying a sigmoid function) and there exists a given time for a given set of reservoir and fluid properties, after the effect of anisotropy ceases to exist. This is remarkable because it suggests a way to improve modeling efficiency for reservoirs with strong anisotropic permeabilities.

Our results also explain why most other static averaging methods fail. The analytical expression can be used as a fast SAGD predictive model suitable for history matching purposes.
Log-Based Identification of Sweet Spots for Effective Fracs in Shale Reservoirs
Authors: Hashmy Khaled , Abueita Samir , Barnett Craig , Jonkers Jos
Published: December 2011

Hydro-fracturing and long horizontal sections are needed to generate economic production volumes in shale reservoirs. Many operators resort to multi-stage fracs in horizontal sections that are often sparsely surveyed with LWD or wireline logs. The trend is to space out different frac stages, more or less evenly, along the length of the horizontal with the expectation that reservoir characteristics will conform to those encountered in the vertical pilot hole.

LWD and wireline logs examples presented here distinctly highlight sweet spots with superior reservoir characteristics that are likely to have excellent flow characteristics. Perhaps equally important is the delineation of zones that have inferior reservoir properties, where hydro fracturing will be far less effective. Sweet spots enable operators to concentrate on the most suitable intervals for stimulation to obtain a bigger bang for their bucks.

In marine shales, LWD Spectral Gamma measurements highlight intervals of high Uranium corresponding to elevated Kerogen levels which are zones that are expected to be rich in hydrocarbons. An image log is generated from the cumulative GR to provide structural information. Examples show delineation of sweet spots using LWD density and Spectral Gamma combination.

A LWD Acoustic measurement that employs a unique transmitter provides split fast and slow shear in horizontal sections – yielding elastic properties in the vertical and horizontal directions thereby providing information on anisotropy of these reservoirs. This once again brings out the lateral inhomogeneity and points out the sweet spots where frac dollars need to be concentrated.

The cost of well surveys in a horizontal shale formation can be less than the expenditure on a single frac stage. A Quad-Combo is sufficient for a meaningful evaluation that will permit operators to concentrate on intervals with better reservoir characteristics and thus achieve improved stimulation of the formation.
Investigation of Top-Down In-Situ Combustion Process in Complex Fractured Carbonate Models: Effects of Fractures’ Geometrical Properties
Authors: Fatemi S. Mobeen , Kharrat Riyaz , Vossoughi Shapour
Published: December 2011

The top down In-Situ Combustion (ISC), involves the stable propagation of combustion front from top vertical injector to the bottom horizontal producer. Besides laboratory studies in conventional sandstones, no application of the process in fractured carbonates has been addressed yet. In this paper a successful combustion tube experiment and history match of Iranian low permeable fractured heavy oil reservoir called Kuh-E-Mond, is presented and accompanied with details of experimental and simulation model. Validated model has been modified further to investigate the feasibility of Top-down ISC in fractured reservoirs mimicking block scale combustion cells. Effects of fractures geometrical properties such as orientation, location, extension, density, spacing, disconnection and dispersion have been considered. Investigation of aforementioned geometrical properties performed for the case of presence of networked fractures (presence of both vertical and horizontal fractures). Results confirmed higher outcome in the case of optimum vertical or horizontal fractures density and spacing. Laterally located vertical fractures enhanced the process in terms of ultimate oil recovery and sweep efficiency. Longer vertical fractures and higher degree of fractures dispersion through the reservoir improved the recoveries compared to the case of extended horizontal fractures and higher degree of horizontal fractures dispersion through reservoir. Depending on the reservoir parameters (such as fracture and matrix permeability) there is an optimum length of vertical fracture in which it enhances the recovery. This means very long extension of vertical fractures could cause early oxygen breakthrough and as a result lower sweep efficiency and oil recoveries. Simulation analysis revealed that Top-down In-Situ Combustion has higher feasibility for the reservoirs with highly networked fractures such as those occurring in the Persian Gulf coast.
Practical Control of SAGD Wells with Dual Tubing Strings
Authors: Stone Terry , Brown George , Guyagular Baris , Bailey William J. , Law David Hin-Sum
Published: December 2011

Practical methods of operating dual/triple tubing strings based on temperature monitoring that is currently available to achieve uniform steam chamber development and enhanced production in a Steam Assisted Gravity Drainage (SAGD) process are presented. The work is motivated by the fact that many operators use dual tubing strings for designing and optimizing steam chamber development. Flow in the region of the SAGD horizontal well pair is often irregular and dual tubing strings may help to even out and improve both injection and production. Problems that operators have with multiple tubing strings in wells include both their control and design. Both injector and producer have two tubing strings each: one landed at the toe and the other at the heel. Control points are applied on each injection tubular. Injection at these control points is regulated by a Proportional-Integral-Derivative (PID) feedback controller monitoring temperature differences between injected and produced fluids.

The PID controller will attempt to accomplish two goals (i) achieve evenness in injection and production conformance along both wells, (ii) enforce a specified temperature offset between the injector and producer in order to improve oil production and reduce steam production and injection. Sensitivity of the feedback controller will be examined for (i) heterogeneity where several permeability patterns will be tested to gauge the effectiveness of coping with reservoir complexity, (ii) update frequency where a comparison will be made between instantaneous and periodic updating of the controller error terms, (iii) ability of the controller to cope with early temperature rises in produced fluids. Well monitoring is accomplished through the use of high temperature fibre-optic temperature sensing that is currently available. Results and discussion are offered on whether an additional tubular landed at the midpoint of both wells will benefit production from a heterogeneous reservoir.
Design of Caprock Integrity in Thermal Stimulation of Shallow Oil-Sands Reservoirs
Authors: Yuan Yanguang , Xu Bin , Palmgren Claes
Published: December 2011

Stakeholders in the in-situ oilsands development take the caprock integrity issues very seriously. The industry is faced with the challenge of determining an optimal operating pressure in the reservoir. In general, the pressure should stay low enough to ensure the caprock integrity while being high enough for enhanced oil production and economics. This paper presents a comprehensive work program on the subject for a shallow oilsands play.

Caprock integrity is concerned about the induced stress and deformation in the caprock during the thermal stimulation of the oilsands reservoir. A mini-frac test program was undertaken to define the original in-situ stress state. Laboratory tests were carried out to measure the deformation and strength properties. Simulations were run to calculate the induced stresses and evaluate them against the mechanical strength. Consequently, a factor of safety is delivered for a given operating pressure. This paper will cover all these geomechanical work components. Both field data and theoretical considerations are included to augment the technical descriptions.
Prediction of the Viscosity of Solvent Diluted Live Bitumen at Temperatures up to 175°C
Authors: Motahhari H. , Schoeggl F. F. , Satyro M. A. , Yarranton H. W.
Published: December 2011

Accurate predictions of heavy oil and bitumen viscosity as a function of temperature, pressure, and composition are required for the design of thermal and solvent based recovery methods. In this case study, the applicability of the recently developed Expanded Fluid viscosity correlation is tested on measured viscosities of diluted dead and live bitumen at temperatures from 20 to 175°C and pressures up to 10 MPa. The data were collected for: 1) an Alberta bitumen, 2) a condensate, 3) diluted bitumen with 3, 6 and 30 wt% condensate, 4) live bitumen, and 5) diluted live bitumen with 3 and 5.9 wt% condensate. The live oil viscosity was 820 mPa.s at 50°C and 2.5 MPa compared with a dead oil viscosity of 3180 mPa.s.

The Expanded Fluid (EF) viscosity correlation relates viscosity to density at any given pressure and temperature; it requires three parameters for each fluid. In this study, the dead bitumen and the condensate solvent are treated as single components and the viscosity correlation parameters are determined by fitting viscosity data. The parameters for the solution gas, live bitumen, and the bitumen-solvent mixtures were determined from mass based mixing rules. The parameters for the pure components that made up the solution gas were previously determined.

The correlation was fitted to dead Alberta bitumen and the condensate with average relative deviations of 11% and 1.5%, respectively. The viscosity of the live bitumen was predicted to within 20% and 28% of the measured value based on measured and calculated mixture densities, respectively. Diluting the live and dead bitumen with 3 to 30 wt% solvent reduced the viscosity by one to three orders of magnitude and the viscosities were predicted with an average relative deviation under 16 and 37% based on measured and calculated mixture densities, respectively.
Modeling of Asphaltene Precipitation Due to Steam and n-alkane Co-injection in the ES-SAGD Process
Authors: Badamchizadeh Amin , Kohse Bruce F. , Kumar Anjani
Published: December 2011

The world energy demand is continuously increasing. Therefore heavy oil and bitumen reservoirs are driving more attentions for world energy supply. There are large amount of bitumen reserves in Canada. Only very small portion of bitumen reserves (~15%) in Alberta is mineable, and rest must be recovered using in-situ techniques. Bitumen viscosity can be reduced substantially by heating or dilution with a solvent. Steam Assisted Gravity drainage (SAGD) has been employed commercially to recover bitumen from Athabasca oil sands. This method requires large amount of water, facilities for water treatment, and natural gas to generate steam. There have been attempts to develop and optimize hybrid SAGD processes to reduce water consumption during bitumen recovery by steam. The co-injection of steam and solvent additives (e.g. ES-SAGD, SAP, SAS) can improve bitumen recovery due to its viscosity reduction by dilution with solvent and heating by steam. The experimental and pilot studies with steam and n-alkane co-injection shows enhanced oil recovery, and reduction in steam consumption (Nasr et. al., 1991, 2001, 2002, 2003). The phase behaviour of the bitumen and n-alkane solvents at SAGD operating condition is very complex and there is possibility of multiphase formation or asphaltene precipitation. The recent pore scale experimental study of this process has shown evidence of asphaltene precipitation during the ES-SAGD with n-alkanes (e.g. Pentane, Hexane) (Mohammadzadeh et. al., 2010). There are few published asphaltene precipitation data for Athabasca bitumen and n-alkanes at different temperature and pressure in the literature (Sabbag et. al. 2006). These data were used to develop an EoS model for the asphaltene precipitation using the CMG-WinProp Asph/Wax multiphase flash calculation. The asphaltene precipitation during the steam and n-alkane co-injection was studied using STARS thermal reservoir simulation model. This paper explains a method to characterize Athabasca bitumen based on the experimental SimDist data. A technique for tuning the solid solubility model parameters was addressed to develop asphaltene precipitation model for n-heptane and Athabasca bitumen. Also the asphaltene precipitation modeling with STARS, its effect on the steam chamber development and ES-SAGD performance are discussed.
Importance of Shale Anisotropy in Estimating In-Situ Stresses and Wellbore Stability Analysis in Horn River Basin
Authors: Khan Safdar , Ansari Sajjad , Han Hongxue , Khosravi Nader
Published: December 2011

Shale formations have laminated structures which result in significant differences in mechanical properties along the orientations parallel to and perpendicular to laminations (bedding planes). These differences lead to anisotropic horizontal stresses. Failure to consider the effect of anisotropic behavior of shale can have severe consequences for drilling. In rocks with anisotropic mechanical properties and strength, there is a high risk of wellbore instability while building deviation angle from vertical sections. Conventional wellbore stability analysis approaches do not consider material anisotropy and laminated nature of shales, which can result in underestimated stresses leading to incorrect safe trajectory or mud-weights.

Shale formations in the Horn River Basin (HRB) are strongly anisotropic with anisotropic ratios varying from 1.2 to 3.5. In this paper, the authors demonstrate the importance of considering anisotropy in estimation of in-situ stresses and wellbore stability analysis. Two field case study examples are presented to underscore the consequences of neglecting anisotropy in wellbore stability analysis.
Comparative Study of Multistage Cemented Liner and Openhole System Completion Technologies in the Montney Resource Play
Authors: Wilson Brad , Lui David , Kim James , Kenyon Mike , McCaffrey Matt
Published: December 2011

The Montney Formation Resource Play, which straddles the border between the Canadian provinces of British Columbia and Alberta, is considered by many to be one of the largest natural gas resource plays in North America. Original gas-in-place estimates for the Montney range from a minimum of 80 tcf to as high as 700 tcf. Despite horizontal, multistage stimulation being common practice to effectively exploit tight gas sand and shale reservoirs, determination of the optimal methodology and identification of the parameters that affect optimization have yet to be fully understood.

This paper compares two different multistage hydraulic fracturing technologies applied in the Lower Montney Formation: cemented liner and openhole multistage system (OHMS) completions. In-depth analysis was performed on field data from 15 wells divided into two separate geographical areas within the same field. Comparisons included production analysis, lateral lengths, number of stages, stage spacing, proppant volumes, and pump rates. Additionally, operational time and cost comparisons on a per well and per stage basis for both technologies were determined.

Based upon the field data analyzed, the application of OHMS completion technology is appropriate for the Lower Montney in the region of the play studied. Application of this technology for the wells selected in the two study areas resulted in both greater initial production rates and overall cumulative production than cemented liner completed wells. Additionally, less time was required to perform the fracture stimulation job when using OHMS technology as compared to cemented liners. Both the average total cost of completion and average cost per stage in conducting cemented liner jobs was higher than employing OHMS completions.
Technical Feasibility of Polymer Injection in Heavy Oil Reservoir BAINF60 and BAMED78: Intercampo Norte - Through Predictive Models
Authors: Hincapie Rafael , Alvarez Carlos , Vargas Armando
Published: December 2011

Due to its maturity, many fields of light-medium crude oil have entered a stage of declining production. This allows putting into perspective the crucial role that non-conventional hydrocarbon resources must meet in providing energy for the future, such as heavy oil, extra heavy oil. Enhanced recovery techniques to exploit these reservoirs are quite varied, including the polymers injection; it is to add polymers into the water injection of high molecular weight before being injected into the reservoir, thereby improving mobility ratio water - oil. This study examines the feasibility of applying the polymer injection process in mature reservoirs BAINF 60 and BAMED 78 of Interfield North Area, located in Bachaquero Zulia State, Venezuela; using the simulation software Polymer Flood Predictive Model (PPMTM) is based predictive models. The methodology included the evaluation of field’s worldwide parameters; initially making a state of the art of the process, generating a set of application criteria; the simulation of these parameters defined the injection and production in the area. This study analyzed the parameters of viscosity, ° API, sand thickness, porosity, permeability, temperature and depth. Among the most important results obtained is that for the BAINF 60, applies the polymer injection process to an injection rate of 120 bbl / day, with a well spacing of 700 feet, a polymer concentration of 1800 ppm and solution viscosity of 32 cps, giving a recovery factor of 56%, 19% increase respect for the original. In the BAMED 78 case, this is limited by the high viscosity oil has, recommended by studying the application of any process mentioned area.
Enhance Offshore Heavy Oil Recovery by Cyclic Steam-Gas-Chemical Co-stimulation
Authors: Sun Yongtao , Zhao Lichang , Lin Tao , Zhong Liguo , Yu Di , Lin Hui
Published: December 2011

There are abundant heavy oil resources in Bohai Offshore Oilfield. In past, only limited heavy oil reservoirs are recovered by cold production such as ESP, and uneconomic oil production(less than 30 m3/day in general) is obtained. Although conventional steam injection such as cycle steam stimulation is an effective onshore enhancing heavy oil recovery method, it is challenging to setup conventional steam generator on production platform for offshore heavy oil production. In consideration of the pothential of Thermal production for offshore heavy oil recovery, a portable and compact steam and flue gas generator is developed to employ cyclic steam-gas-chemical stimulation, and the whole injection system consists of gas generator, water treatment unit, fuel and chemical tanks, insulated surface pipe and tubing. Steam and flue gas are coinjected at the pressure up to 20MPa, content of flue gas is 13.1wt%-28.3wt%. The stimulation or EOR principles of cyclic steam-gas-chemical co-stimulation based on the synergetic effect of fluid injected include reduction in oil viscosity by heating and gas solution, enlargement of heat sweeping efficiency by coinjected gas, decrease in heat loss, expansion of heated porous rock and saturated fluid, improvement in fluid injectivity and sweep efficiency, and reservoir protection or injectivity enhancement and other favorable reaction by chemical additives such as foaming agent. Based on experiment and numerical simulation, the rational temperature of steam and gas coinjected is 300°C, and the volume ratio of gas to steam is about 0.3-1.0 under barometric pressure depending on reservoir condition.

In past two years, cyclic steam-gas-chemical co-stimulation are applied to five offshore heavy oil wells completed thermally or non-thermally with screen pipe, periodical steam injection is about 3000-5000 tons, and flue gas generated is injected together, chemical additives such as corrosion retarder injected alternatively, and a certain amount of nitrogen could be injected through annulus between tubing and casing to insulate tubing and vary injected fluid composition. As a result, up to 3 times of oil production rate in average compared to that of cold production is observed, and the peak oil production is more than 100 m3/day, and cyclic oil production increase is more than 5000 m3. In this paper, EOR principles, injection optimization, engineering design and field testing of cyclic steam-gas-chemical co-stimulation are introduced in detail.
Integrated Reservoir Characterisation using Borehole Images, Open Hole Logs and Cores to establish Rock Facies and Sediment Dispersal Orientation of an Unconsolidated Clastic Heavy Oil bearing Reservoir in the State of Kuwait
Authors: Jha Madan , Ahmad Fatma , Al-Sammak Ibrahim , Ahmad Khalid , Baradi Ali
Published: December 2011

An unconsolidated clastic reservoir of Middle Miocene age is under full field development plan in the State of Kuwait. Underlying the shale cap rock, main hydrocarbon bearing reservoir consists of two sand bodies separated by predominantly shale interval present throughout the field. To determine the role of facies and depositional environment in controlling the orientation and quality of the reservoir, an integrated analysis of borehole images, open hole logs and core data from wells spread across the field was successfully attempted.

Fifteen identified generic image facies principally based on lithology and reservoir quality with core data validation were grouped into six genetically related associations. Facies recognition used criteria of image textural variations, dip patterns, direct recognition of features and relationships of cementation, bioturbation and sediment deformation. Statistical analysis of the identified sandy facies of upper reservoir unit indicated high abundance ratio and preferred distribution trend while no significant distribution trend observed for the lower reservoir unit.

Observations from the image and core data helped to define depositional environment and sub-environments. Results indicate that depositional setting was created by succession of several depositional environments such as shore face, coastal plain of fluvial & distributary channels and lagoon. The high angle cross-bed features distinctly noticed are interpreted to be deposited in confined depositional environment of channel sand bodies, suggesting a major paleo sediment transport orientation. The marine shale deposited during a major flooding event on top part of the hydrocarbon bearing reservoir acts as cap rock. Tight carbonate cemented sandstone intervals also identified at various levels within the reservoir. In general, the formations exhibit distinct episodes of regression and transgression events marked by erosive and flooding surfaces.

The identified rock facies relationship and depositional environment provided significant lead in formulation of full field geological model.
Contemporary Approach Coupled with Traditional Techniques Tackles Extreme Wellbore Environment in Schoonebeek Heavy Oil Field
Authors: Foster Andrew , Pollema Auke , Petitt Ian , Heathman James , Johnson Carl , Schlepers Rudy
Published: December 2011

The Schoonebeek heavy oil field was first developed by Nederlandse Aardolie Maatschappij BV (NAM) in the late 1940s. Due to economics, it was abandoned in 1996. In 2008, the Schoonebeek Redevelopment Project, using a gravity assisted steam flood (GASF) design concept, was initiated with 73 wells (44 producers, 25 injectors and 4 observation wells).

Steam injection and cool-down cycles subject a cement sheath to some of the most severe load conditions in the industry. Wellbore thermal modeling predicted surface and production sections would experience temperatures in excess of 285°C [545°F] and considerable stress across weak formations. A key design requirement was long-term integrity of the cement sheath over an expected 25-30 year field life span. Complicating this requirement was the need for lightweight cementing systems, as lost circulation issues were expected in both hole sections, particularly in the mechanically weak Bentheim sandstone.

The long-term integrity challenge was divided into chemical and mechanical elements. Prior research on high-temperature cement performance by the operator provided necessary guidance for this project. Laboratory mechanical and analytical tests were conducted to confirm the high-temperature stability of the chosen design.

In addition to using lightweight components, foaming the slurry allowed the density, mechanical and economic targets to be met. A standardized logistical plan was put in place to allow use of the same base blend for the entire well, adjusted as needed using liquid additives and applying the foaming process when necessary. This single-blend approach greatly simplified bulk-handling logistics, allowing use of dedicated bulk-handling equipment.

The first well was constructed in January 2009; all 73 wells have been successfully cemented to surface. The steaming process, initiated in May 2011, has progressed with no well integrity issues to date.
Investigation of Steam Assisted Gravity Drainage (SAGD) and Expanding Solvent-SAGD (ES-SAGD) Processes in Complex Fractured Models: Effects of Fractures' Geometrical Properties
Authors: Fatemi S. Mobeen , Kharrat Riyaz , Vossoughi Shapour
Published: December 2011

The Steam Assisted Gravity Drainage (SAGD) process has been studied theoretically and experimentally in conventional models and reservoirs and is found a promising EOR method for certain heavy oil reservoirs, but its applicability for fractured systems has not yet been investigated. In this work simulation studies of the SAGD process were made on different fractured models consisting of fractures in both Near Well Region (NWR) and Above Well Region (AWR) and also in the presence of networked fractures. Double porosity/double permeability fractured models were developed and results were compared with conventional non-fractured model. Various fracture geometries such as orientation, length, discontinuity, dispersion, location, and networking were studied. Results indicated a better performance in terms of oil recovery and sweep efficiency in the presence of vertical fractures. Longer vertical fractures seemed to have even more beneficial effects. Horizontal fractures revealed detrimental effect on oil recovery and the performance became worse for longer horizontal fractures. Discontinuous horizontal fractures produced a better performance especially when combined with continuous vertical fractures (networking). Vertical fractures helped growth of steam chamber in vertical direction which resulted in higher oil recovery. However, horizontal fractures seemed to inhibit growth of the steam chamber in vertical direction, hence retarding oil recovery. In addition to SAGD, ES-SAGD process has also been investigated for both conventional and fractured simulation models. Simulation analysis confirmed the synergetic effect of solvent injection along with steam since for both conventional and fractured models ES-SAGD had a higher rate of production and higher ultimate oil recovery.
Pressure Maintenance and Improving Oil Recovery with CO2 Injection in Heavy Oil Reservoirs
Authors: Zheng Sixu , Li Huazhou , Yang Daoyong
Published: December 2011

In this paper, techniques have been developed to experimentally evaluate performance of CO2 injection in heavy oil reservoirs for pressure maintenance purpose. More specifically, a three-dimensional (3D) physical model consisting of five vertical wells and three horizontal wells is used to examine effect of well configurations on pressure maintenance and oil recovery with CO2 injection in heavy oil reservoirs. The initial oil saturation, oil production rate, water cut, gas-oil ratio, ultimate oil recovery, and distribution of residual oil saturation are examined under various well configurations, which can be optimized to maximize heavy oil recovery when CO2 injection is employed for pressure maintenance purpose. The well configuration with a horizontal producer plus four vertical injectors is found to achieve a better performance than the conventional five-spot well configuration, while the oil recovery is experimentally determined to be 15.7% of OOIP during CO2 injection process.
Performance of a SAGD Process with Addition of CO2, C3H8, and C4H10 in a Heavy Oil Reservoir
Authors: Egboka Chukwuka , Yang Daoyong
Published: December 2011

A comprehensive simulation has been conducted to evaluate performance of the conventional SAGD and CO2-solvent(s)-assisted SAGD processes in a real field case. Compared to the steam-only process (i.e., the conventional SAGD process), addition of CO2, C3H8 and C4H10 to the steam stream has been found to slightly reduce the oil recovery proportionally if the total injection rate is maintained constant. As for adding one agent, the C4H10-SAGD and CO2-SAGD processes lead to the smallest and largest reduction in oil recovery, respectively. The optimum C4H10 concentration is 5% volume fraction. As for adding two agents, the C3H8-C4H10-SAGD process results in the lowest reduction in oil recovery. C3H8-C4H10 is the optimum binary solvent mixture with its volume fraction of 5% each in the mixture. As for adding three agents, the CO2-C3H8-C4H10-SAGD process leads to the highest reduction in oil recovery. The optimum concentration of CO2-C3H8-C4H10 ternary solvent mixture is found to be 5% for each solvent by volume. Although CO2 has the least oil recovery, it achieves the highest SAGD thermal efficient among the solvent assisted processes. This means that, in addition to its being stored the most in the formation, CO2 has the most capability to hinder heat transfer and to maintain the most thermal efficiency in a SAGD process. The energy requirements are reduced substantially with addition of the three solvents to the steam stream in the SAGD process, though the oil recovery is slightly reduced.
Complex Fluid Flow and Mechanical Modeling of Metal Progressing Cavity Pumps PCP's
Authors: Berton M. , Allain O. , Goulay C. , Lemetayer P.
Published: December 2011

The metal-to-metal progressing cavity pump is an attractive artificial lift for heavy oils in cold or hot application. The principal objective of this paper is to present the latest developments in numerical simulations tools aimed at understanding and optimizing the operation of a PCP with metallic stator. This paper is divided into three parts: the first focusing on the precise implementation of a viscoplastic thixotropic model while the second is the validation of the numerical models developed around 3D calculations based on a volumetric pump and comparing them to experimental data. The last part is oriented towards the full 3D fluid structure interaction model, used to estimate the stress and strain amplitudes in the metallic stator, to finaly predict its life span or optimize its design.
Worldwide Drill-Stem-Testing Experiences in Heavy and Viscous-Oil Offshore Environments That Improve Operational Efficiency
Authors: Salguero Alejandro , Wendler Curtis , Mansilla Cidar , Woolsey Steven
Published: December 2011

Well testing operations in challenging environments are becoming more common, and as a result, testing technologies have had to continually improve or develop newer techniques that can meet the more corrosive needs in the new areas. These testing methods must not only achieve operational efficiency, increase personnel safety and protect the environment, they must address additional challenges in the new environments where current development is taking place. In spite of the ongoing improvements, however, there are still scenarios that remain problematic, and one the most challenging continues to be the production and well testing of heavy-oil reservoirs in sandstones or carbonates. This is particularly true when testing operations are performed offshore.

Heavy oils normally are defined as those with an API gravity below 20 degrees with very high viscosities, a variable that is a major factor in determining the flowing capacity of oil through the reservoir, the completion string, and surface facilities. Pressures and low temperatures can increase the viscosity of the oil to an even higher value, depending on the wellbore characteristics, geographical area, and the PVT properties of the crude. While most onshore reservoirs are produced using cold production or steam injection to reduce the viscosity, offshore environments present more difficult scenarios due to the low temperatures at the sea bed and in the ocean thermo-cline regions which further complicate the typical complexity of all operations in this type of environment.

Enhanced simplicity and reliability is critical in offshore development because of the increased intervention cost compared to the cost of onshore cases and the need to maintain environmental safety. Thus, careful initial planning of these operations remains paramount.

This paper reviews experiences that have occurred while testing heavy-oil reservoirs using a wide range of equipment configurations and procedures. The authors feel that this information will be extremely valuable for operators and service personnel who are planning well testing operations offshore.
Advancing Thermal and Carbon Dioxide Recovery Methods beyond their Conventional Limits: Downhole Innovation
Authors: Capper Laura , Kuhlman Myron , Vassilellis George , Schneider M. J. , Fitzpatrick Nick
Published: December 2011

Steam or CO2 injection methods account for most of the oil recovered worldwide with Enhanced Oil Recovery (EOR) methods. Currently heavy oil production is less than 7% of the world’s oil production; this percentage is not expected to increase dramatically without significant changes in reservoir management. Steam and CO2 have been used successfully since early 1960s -- steam in viscous heavy oils and CO2 mostly in pressurized light oil fields but also in some heavy oil fields. What limits a wider application is depth and high pressure for steam and CO2 availability for the relatively large inventory of light oil fields that exist worldwide. Although there is some overlap in fields that could benefit from either application, there are not many recorded attempts to implement both methods simultaneously. Air injection, although it was tried first as an EOR method, has not been widely implemented as in-situ combustion is difficult to control in shallow reservoirs and especially without water coinjection.

The paper describes the benefits that result from operation of a downhole steam generation (DHSG) which combines thermal and nitrogen or CO2 EOR. In addition, by controlling the ratios of steam, excess CO2 and excess O2 (where applicable) it is possible to use in-situ oxidation in a controlled manner and accelerate production of oil. Moreover, the CO2 that is generated by in situ can be used elsewhere. The paper includes discussion of conceptual reservoir simulation and economic studies that demonstrate the applicability of DHSG in deeper warm-climate conventional heavy oil fields, as well as challenging arctic environments.

Advances from the aerospace industry that enabled this DHSG system, the surface processing design, and well placement strategies are also discussed in this article. They provide an overview of the entire recovery system and present an opportunity to develop both virgin resources and oil fields that were prolific in primary and secondary operations and are rightfully candidates for EOR.
The Effect of Unplanned Shutdown to World’s Largest Steamflood Project, Duri Field Indonesia
Authors: Sutadiwiria G. , Azwar N.
Published: December 2011

The Duri field, operated by Chevron under a production sharing contract with Government of Indonesia, is located in Riau province of central Sumatra about 120 km northwest of the city of Pekanbaru. The Duri Steamflood (DSF) Project is the largest Steamflood project in the world. Duri field was discovered in 1941 and start producing with primary production in 1958. Steamflood project started in 1985 and reached the peak production of 300,000 barrels oil per day later on late year 1994. Many well technologies have been applied, related to producer well completion and sand control, injector well completion, artificial lifts, and horizontal drilling to optimize the oil recovery. Heat management process was established to manage the steam injection efficiently. The DSF project was developed from Area-1 until Area-12 with different pattern sizes and configurations. The pattern sizes range from 5.5 acres to 15.5 acres. Pattern configurations vary and consist of 5-spot inverted 7-spot inverted and 9-spot inverted patterns. The DSF plans for further expansion to northern part of Duri field by developing new areas and other areas such as Duri "Ring", the area surrounding the existing producing field. Until 1998, steam was generated using oil as fuel but in year 2000, generators were converted to natural gas. The gas consumption reaches 414 MMscfd and mostly supplied from neighbored production sharing contractor ConocoPhillips using 28 inch x 530km pipeline transmission operated by 3rd party.

On 29 September 2010, when DSF was producing 190,000 barrels oil per day, a failure event occurred that resulted in a release of gas from the pipeline. The accident cut the gas supply to DSF, caused the shutdown of steam generation facilities, and forced the world’s largest steamflood project to shut some of the producer wells for several days. This incident was the first "no-steam" incident to Duri steamflood project operation.

The impact was severe. Production dropped to 58,000 barrel oil per day, and gradually increased back after the gas supply was ramped-up to normal levels. The gas supply was ramped-up and back to normal in 25 days. The production ramped-up, reached the peak slightly lower than before the event and production is continuing to recover with different mode where the decline is lower than before the incident. After the initial incident, there were other events, related to gas supply issues and interruptions of steam supply from cogeneration plant (COGEN) that have negatively impacted the production recovery. This paper shows the on-going massive efforts of Chevron and Government of Indonesia to bring the world’s largest steamflood project to full recovery and sustainably rejuvenate the Duri Field production.