bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.