bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Swelling Effect and Viscosity Reduction of Solvents-CO2-Heavy Oil Systems
Authors: Li Huazhou , Zheng Sixu , Yang Daoyong 
Published: December 2011

Abstract
In this paper, techniques have been developed to examine the enhanced swelling effect and viscosity reduction of CO2-saturated heavy oil with addition of rich solvent C3H8. Experimentally, PVT tests are conducted to measure the saturation pressure, swelling factor and viscosity of the C3H8-heavy oil system and C3H8-CO2-heavy oil system, respectively. It has been found that an increased swelling effect of heavy oil is obtained by adding rich solvent C3H8 into CO2 stream. An enhanced viscosity reduction of the CO2-heavy oil system is also achieved in the presence of rich solvents such as C3H8. Theoretically, two binary interaction parameter (BIP) correlations in Peng-Robinson equation of state (PR-EOS) have been proposed for respectively characterizing CO2-heavy oil systems and C3H8-heavy oil systems by treating each oil sample as a single pseudocomponent with its molecular weight and specific gravity. The BIP correlations together with the PR-EOS can be used to predict the saturation pressures and swelling factors of the C3H8-CO2-heavy oil systems with a good accuracy. Also, in comparison to other mixing rules, the Lobe’s mixing rule is found to be more appropriate for quantifying viscosity reduction of the heavy oil with dissolution of CO2 and/or C3H8.
Steam Injection Experiences in Heavy and Extra-Heavy Oil Fields, Venezuela
Authors: Vega Riveros Gina , Barrios Hugo 
Published: December 2011

Abstract
The exploitation and development of large heavy and extra heavy oil fields in Venezuela represents one of the largest hydrocarbon accumulations in the world. These deposits can be found at the Orinoco Heavy Oil Belt in Eastern Venezuela, the Bolivar Coast Fields in Western Venezuela and Santa Barbara and Pirital Fields in the Northeast of Venezuela. The Orinoco Heavy Oil Belt represents a 90% of the discovered extra-heavy oil in the country.
Enormous deposits of hydrocarbons can be found in "Cerro Negro", "Machete", "Hamaca" and "Zuata" that belong to the Orinoco Heavy Oil Belt. These fields contain extra-heavy crude of 8 to 9 °API, an oil viscosity of 8,500 cp, an original depth of 2,900 ft and a thickness of 217 to 287 ft. The sand depositional environments are originally fluvial or deltaic and laterally discontinuous.
Santa Barbara Field contains heavy oil crude of 16 to 19 °API, an oil viscosity of 510 cp, a depth of 200 to 1,150 ft and sand thickness of 40 to 253 ft. The fields come from delta derived sandstones enviromentals. Bachaquero, Lagunillas and Tia Juana Fields in the Bolivar Coast Field contain heavy crude of 11 to 15 °API, viscosity of 100 to 10,000 cps, depth of 1,000 to 3,000 ft and sand thickness of 50 to 300 ft. The sand consists of non-marine sediments, eventual transgressions and conglomerate sandstones depositional environments.
The fields were studied to extract information about successful application and evaluation of cyclic steam stimulation (CSS). In the Northern part of Tia Juana Field where the viscosity was higher than expected (typically 20,000 cp), a steam assisted gravity drainage (SAGD) Pilot was implemented. Statistical analysis allowed the quantification of the parameters that affect the incremental recovery factor. As a result, it was found that the basic controls are °API, viscosity, depth, thickness and well spacing.
Thermal recovery processes are mainly applied to deposits less than 1,100 m of depth, oil viscosity greater than 50 cp, gravity less than 20 °API and typical well spacing of 2-5 acres. The most common applied method was cyclic steam stimulation (CSS) with a positive incremental of oil-steam ratio, from 1.5 to 6.8. Steam Assisted Gravity Drainage (SAGD) in horizontal wells was applied increasing significantly the recovery efficiency, higher than 50%.
Simulation Study of Thermal Well Test Analysis in Steam Injection Wells
Authors: Ghahfarokhi Ashkan Jahanbani , Jelmert Tom Aage , Kleppe Jon 
Published: December 2011

Abstract
Heavy oil reservoirs constitute a huge proportion of total world oil reserves. Among different thermal recovery methods, steam injection is the most widely used method in this type of reservoirs. Monitoring of swept volume over time is very important for evaluation of a thermal project. Thermal well testing offers an inexpensive method to estimate flow capacity and swept volume in thermal recovery processes. Pressure falloff tests are usually used for this purpose.
Estimation of steam zone properties and swept volume from falloff test data in this study is based on the theory developed by Eggenschwiler et al. (1980), assuming a composite reservoir with two regions of highly contrasting fluid mobilities and the interface as an impermeable boundary. Consequently, the swept zone acts as a closed reservoir for a short duration, during which the pressure response is characterized by pseudo steady state behavior.
The purpose of this work is to investigate the feasibility of thermal well test analysis and effects of different parameters. Pressure falloff testing is simulated using a numerical thermal simulator. The generated pressure falloff data are then analyzed to calculate swept volume and reservoir parameters. Different gridblock models are designed.
Results of this study show that the swept volume, swept zone permeability and skin factor can be reasonably estimated from pressure falloff tests. The effects of gravity, dip, permeability anisotropy and irregular shapes of swept zones are investigated. It is found that these factors do not affect the estimated results significantly. Results of 3D models show that the estimation of flow capacity and steam swept volume depends on the vertical positions where pressure data are measured (i.e. the location of pressure gauges). This finding should be considered in thermal well test interpretation.
Samaria Neogeno Exploitation Plan: FEL Approach and Pilot Test Implementation
Authors: Arteaga Marcela , Aguilar Alfredo , Czwienzek Fabiola , Salve Javier , Aldana Jose Luis 
Published: December 2011

Abstract
This paper presents the planning and development of a project in Samaria Neogeno field, which is a heavy oil field that is located 17 kilometers from Villahermosa, Mexico. The front-end loading (FEL) method was used to design the development plan of the Samaria Neogeno field and to complete the project. FEL is considered to be an international best practice. The Samaria Neogeno field is currently undergoing a period of substantial development, which has resulted in a potential production increase of 30,000 bbl/day. This project is a result of the collaborative efforts of PEMEX and Halliburton.
In general terms, the FEL method includes three stages: visualization, conceptualization, and design. The primary activities include the identification and characterization of the uncertainty variables, definition of decision variables and scenarios, and a stochastic simulation of each scenario. One scenario represents a specific exploitation plan. By using the stochastic simulation process, the degree of risk is quantified and measured by standard deviation; consequently, each scenario evaluated was associated with its level of risk. The consideration of the standard deviation parameter, in addition to the economic indicators, promotes better decision making.
The development of the Samaria Neogeno project has been through the three FEL stages, and the execution of the steam injection pilot project. In the visualization stage, multiple scenarios were evaluated; the higher value options were designed for cold production in the early years, followed by the incorporation of hot production in the short- and mid-term phases. In the conceptualization stage, the most valuable scenario was selected, which led to the development of a steam injection pilot project. The steam injection pilot project represented the largest contribution of information regarding the reservoir and response with steam injection. The average production per well increased from 240 to 1,170 bbl/day, and 30 to 40 barrels of oil was recovered for each ton of steam injected. After obtaining these results, a mass development plan was created, and this plan will be implemented during the current year.
The successful results at Samaria Neogeno field highlights the added value of the FEL method as an international best practice.
Avert Steam Pipeline and Piping Failure and Steam Leaks in the Field
Authors: Majeed Mohammed. A. 
Published: December 2011

Abstract
Steam piping and pipeline whipping, bowing, buckling and jumping are some of the phenomenon observed in the field due to improper design and inadequate commissioning procedures. As a result, ‘steam flood’, ‘cyclic steam stimulation’ and ‘SAGD’ operations experiences long steaming hold-ups, extended shutdowns, production losses and environmental clean-up
Steam pipelines up to 32" diameter and 30 km length, with 11 - 15 MPa design pressure and 250-340 deg C design temperature for quality of steam from 80 to 100%, are being designed with high strength material and thin wall designs. Although, designs are robust and utilizes proven stress analysis tools, but are often fail to address the common field issues of unequal warming, condensate buildup and severe slugging encountered during the commissioning and at the start of the new steaming cycle. Also, piping connections lack the provision to accommodate requisite thermal growth and/or the unequal thermal growth between steam piping, production piping, well heads, batteries headers, leading to severe steam leaks.
Steam pipeline and piping are designed with anchors and guides to deal with thermal growth in the horizontal plane. When steam is charged at the ambient temperature, the cooling of the steam in long length pipelines and resulting condensate build up cause thermal gradient in the pipe wall. This thermal gradient coupled with transition in the piping and pipeline elevations are mainly responsible for the bowing, jumping and whipping phenomenon. Pressure, temperature and strain gauge instrumentation should be installed at strategic location to closely monitor and execute uniform warming up to avoid whipping, bowing, buckling and jumping of steam piping and pipelines.
Every incident of whipping, bowing, buckling and jumping of steam piping & pipelines requires detailed integrity evaluation of the affected sections, prior to putting back into operation. Detailed assessment of wall thinning, ovality, dents and other mechanical damages are mandatory to comply with thin wall designs. The result in most incidents is complete replacement of the affected sections, requiring prolonged and costly shutdowns and risk to the producing reservoir due to lack of pressure.
This Poster Presentation will highlight the three areas where steam pipeline are vulnerable to leak and breakages. Condensate induced steam hammerCasing growth and stress loading of the wellheads.Expansion loops and pipe anchors and Pipe Guides management.
Using a New Intelligent Completion Strategy to Increase Thermal EOR Recoveries–SAGD Field Trial
Authors: Shaw Joel , Bedry Mark 
Published: December 2011

Abstract
A completions strategy has been developed for improving both steam injection and production conformance in a thermal- enhanced oil recovery (EOR) project by using intelligent completion technology that incorporates interval control valves (ICVs), well segmentation, and instrumentation. The initial field trial is ongoing in the injector of a Northern Alberta steam-assisted gravity drainage (SAGD) well pair.
Depending on the level of heterogeneity present in the reservoir, the application modeling shows that a 45% reduction in the steam-oil ratio and an almost 70% increase in recovery can be achieved in a SAGD process when both improved injection conformance and producer differential steam-trap control can be applied in a segmented horizontal well pair. A cost-effective intelligent completion solution to achieve this segmentation and control has the potential to add substantial value to field developments resulting in increased energy efficiency and oil recovery through improved steam conformance. The method being developed is also applicable to a wide range of other thermal EOR processes such as cyclic steam stimulation (CSS), steam drive and variations, which include those processes involving solvent additives. The initial field deployment in the injector well was conducted primarily to prove the technology, to demonstrate the feasibility of modifying the steam distribution, and to determine best practices for future developments. A successful installation and commissioning of the intelligent completion has validated the technology substantially. Lessons learned are highlighted.
Early injection test results and data show a significant increase in the understanding of the injection and production behavior in the well pair. The intelligent completion technology under trial and proposed developments should enable more extensive use of downhole measurement and control in thermal EOR projects than has been possible to date. This paper discusses the development of the completion technology, its applicability to thermal conditions, initial field trial results and the plans for further development. A test program to optimize the distribution of the steam injection in the well is underway, and the results to date also will be discussed.
What's The Optimum Well Geometry & Reservoir Parameters in Fracture Carbonate Reservoir Subjected to Steam Stimulation?
Authors: Makkar Fayez A. , Makkar Mariam F. , Makkar Nancy F. 
Published: December 2011

Abstract
As conventional-oil resources are depleted worldwide, vast heavy oil reserves become important as a secure future energy source utilizing thermal or/and non thermal methods. Significant improvements to the effectiveness of these methods can be achieved by developing a basic understanding of the complex displacement mechanisms, developing new techniques, and optimal strategies for in situ characterization of fluid and reservoir characteristics.
Thermal recovery method has been proved as a successful method for heavy oil recovery either cyclic stimulation, steam flooding stimulation or in situ combustion method in order to reduce oil viscosity, increase oil mobility, change the wettabilitiy of the reservoir and also reduce the residual oil saturation. Fracture carbonate reservoirs add more challenge to produce heavy oil, because of dual porosity and severe heterogeneity are occurring in such type of reservoirs.
Steam flooding is preferably applied in low viscosity formation less than 1,000 CP and in shallow depths less than 3,000 ft. Steam zone, hot waterflood zone, cold waterflood zone are formed when steam injected in reservoir consequent mechanisms occurred during steam flooding stimulation are; Gas drive effect of steam displaces the highly mobilized oil in the steam zone, many pore volumes of the steam reduce the oil saturation in the steam zone from initial oil saturation, thermal expansion of oil helps increase its mobility, steam distillation, and also when the temperature increase the relative permeability of oil increases and that to water decreases.
A simulation study has been undertaken to explore the optimum development method of heavy oil recovery in fracture carbonate reservoir with 11.7° API and subjected to steam flooding stimulation which is much like water flooding with arrays of injectors and producers that depend on a pattern size. This is applied on a sector model of 2500 × 2500 ft (Fig. 1) utilize compositional, thermal, and dual porosity options. Different sensitivities have been examined such as well spacing, number of injectors and producers, well completion, sensitize the injection and production parameters, and well type (vertical or horizontal) to evaluate each sensitivity effect on the oil recovery.
The Interpretation of Polymer Coreflood Results for Heavy Oil
Authors: Levitt David , Jouenne Stephane , Bondino Igor , Gingras Jean-Philippe , Bourrel Maurice 
Published: December 2011

Abstract
Polymer and alkali-polymer (AP) flooding are investigated in laboratory corefloods for potential application in a 2000 cP – 5000 cP heavy oil field. An augmentation of oil recovery is noted with the addition of very low concentrations of partially-hydrolyzed polyacrylamide (HPAM), either in secondary or tertiary (i.e. after waterflooding) injection. However, increasing polymer viscosity from 3 cP to 60 cP does not significantly change recovery from two pore volumes (PV) of tertiary polymer injection. Injection of alkali with polymer either in tertiary mode or subsequent to polymer injection yields a significant increase in oil recovery, and is accompanied by a drop in pressure gradient when it follows a polymer slug of similar viscosity. Existing scaling groups for viscous instability are investigated and corefloods in this study and others are found to be in the transition zone or the pseudostable region, while field floods are all in the latter. Growing evidence suggests that polymer flooding can be economically applied to very viscous oils, despite the pessimistic predictions of currently available scaling groups.
Squeeze Cementing Operations in a Thermal Carbonate Steamflood Pilot in the 1st Eocene reservoir, Wafra field, PZ
Authors: Hoadley Steven , Al-Yami Falah , Al-Mutairi Ghanim , Lekia Solomon , Brown Joel , Deemer Art , Al-Dhafeeri Fahad , Barge David , Kadhe Chetan S. , Nwabuogor Collins E. 
Published: December 2011

Abstract
A Large Scale Pilot (LSP) carbonate steamflood has been on injection in a lower targeted section of the 1st Eocene reservoir since June 2009 in the Wafra field located within the Partitioned Zone between the Kingdom of Saudi Arabia and the State of Kuwait. Initial primary oil recovery under cold production in the 1st Eocene interval has been less than 5% because of reservoir heterogeneity, low-gravity viscous oil, and lack of significant aquifer support. Several thermal project tests have been conducted since the late 1990`s to further improve the thermal recovery and understanding in Wafra carbonate reservoirs.
Key technical uncertainties for steamflooding the entire 1st Eocene carbonate reservoir include performance response by layer, reservoir heterogeneity, location and impact of barriers to vertical steam migration, scale deposition and corrosion due to reservoir-steam interactions. To gain thermal response information from different layers in a timely manner and reduce full field development uncertainties around the upper 1st Eocene intervals, the LSP wells were recently recompleted up hole from the "C" to "B" layer. In all, 41 wells, including both steam injectors and producers, were isolated in the "C" layer using cement squeeze operations.
Given the potential for highly permeable connections or conduits within the lower targeted 1st Eocene layer occurring naturally, from rock dissolution during steam injection, or from previous large acid jobs, additional considerations were included in the cement squeeze design to minimize excessive cement losses within the thermal zone. A cement squeeze process was developed to facilitate placement in a zone approaching 425°F while eliminating the possibility of the cement flash setting in the wellbore.
Oil Recovery from Thin Heavy Oil Reservoirs: The Case of the Combined Thermal Drive Pilot in the Morgan Field
Authors: Gutiérrez Dubert , Ursenbach Matt , Moore Gord , Mehta Raj 
Published: December 2011

Abstract
The Morgan Field in Canada produces from the Lloydminster and Sparky sands which are thin heavy oil reservoirs. Early development of the pool was with primary vertical wells in the late 1970's, with some enhanced oil recovery (EOR) projects such as cyclic steam injection and in-situ combustion attempted in the early 1980's. However, the area was essentially non-commercial after the 1986 oil price collapse. In order to regain commerciality, the operators implemented progressive cavity pumps and horizontal drilling, which have proven to be a success. Even with these advances though, recovery is estimated to be less than 10 percent of the original oil in place.
One of the EOR projects attempted was the Combined Thermal Drive (CTD) pilot which was carried out in one of the sections of the field for ten years. After a brief primary production period, the CTD pilot began in 1980 and consisted of three stages. In the first stage, cyclic steam stimulations were performed on individual wells during the first two years. In the next four years, air was added to the injection stream to perform cyclic air-steam stimulations on individual wells. In the last stage, pressure cycling in-situ combustion was performed for approximately four years.
In this paper, historical production and injection records were gathered to perform a technical and economic analysis of the project. After approximately 20 years since the shutdown of the project, the data indicate that this pilot has outperformed all of the other operations carried out in other areas of the field. Not only it has produced the largest amount of incremental oil of all the sections of the field, but it also managed to sustain high production rates for 10 years, which is unparalleled in the area. On the economic side, the data indicate that the project was experiencing a difficult time due to the 1986 oil price collapse. However, an economic analysis under current oil prices and costs suggests that it would have been both a technical and economic success.
This air injection case history represents a good opportunity for those operators facing the challenge to develop thin heavy oil reservoirs.
Kuwait's First Thermal Venture - Success with Resilient Cement
Authors: Eid Ramy , Ranavat Napal Singh 
Published: December 2011

Abstract
Kuwait has a considerable reserve of untapped heavy oil; plans were developed by KOC and embarked on a project to increase its oil production by 2020. Heavy oil production is an ambitious project and will be significant contributer to the overall increase in oil procuction capacity.
As the term "heavy oil" suggests, it is a very viscous oil. The most common methods of heavy oil recovery are: –Cold Heavy Oil Production with Sand (CHOPS)–Cyclic Steam Stimulation–Steam Flooding–Steam Assisted Gravity Drainage (SAGD)
With the focus on the second method, Cyclic Steam Stimulation to enhance the recovery of heavy oil, the design of the cement became important in terms of endurance over the life of the well. In this technique the casing / cement would be exposed to steam injection temperatures as high as 500°F.
In such cases, the cement sheath may crack due the extreme forces acting on the thin sheath of the cement. It is therefore important to know the Young's modulus of both the formation and the cement. This will allow the slurry properties to be adjusted by the use of additives to lower the Young's modulus of the cement to less than of that of the formation. This will prevent damage to the cement sheath.
A fit-for-purpose cement slurry was designed accordingly and applied on a South Ratqa well. Well testing during and after 45 days of steam injection demonstrated that the cement maintained its integrity despite the challenging conditions.