bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integration of 3D Seismic Attributes into Stochastic Reservoir Models Using Iterative Vertical Resolution Modeling Methodology
Authors: Wang Jianwei , Dou Qifeng 
Published: July 2010

Abstract
At early stages of field development, there is generally insufficient well data available to predict reasonable reservoir property distributions. Integrating densely distributed seismic attributes as a secondary constraint can significantly improve the accuracy of reservoir models and reduce uncertainties. However, the scale difference between seismic and well log presents a challenge. Geostatistical modelers encounter both upscale and down-scale issues. We illustrate an iterative vertical resolution modeling methodology to compromise both seismic and log resolutions, and a geostatistical modeling workflow for generating better reservoir models.
Vertical variogram analyses on log data were conducted to determine a well log vertical resolution upper-limit for each geological zone. Under this vertical resolution, the heterogeneity of log properties can be preserved. Different 3D reservoir models with different scales were built. Log porosities were upscaled and seismic attributes were sampled (down-scaled) into these models. A correlation coefficient between log porosity and seismic attributes for each zone in each model was calculated. Within the upper-limit of the log resolution, the best vertical scale that compromises both log and seismic scales was identified based on the best correlation. Horizontal variogram analysis was then conducted based on densely sampled correlated seismic attributes. This method overcame the common difficulty in conducting horizontal variogram analysis using aerially-sparse log data and provided an improved quantitative estimate of the spatial correlation. Sequential Gaussian simulation coupled with collocated co-kriging was then used to populate porosity.
The methodology was applied to the Gullfaks field in the North Sea. The workflow described yielded a reservoir model improved over conventional stochastic modeling methods and greatly reduced uncertainties on porosity distribution away from wells. The chief technical contribution is the presentation of an iterative vertical resolution modeling methodology that compromises both seismic and log resolutions to integrate seismic into a reservoir model.
Basin-Wide Pressure Changes Due to CO2 Storage: California Production as a Reverse Analog
Authors: Jordan Preston 
Published: July 2010

Abstract
Storage of point source generated CO2 (such as from fossil-fueled electricity plants) within geologic strata has been proposed as an alternative to emitting this greenhouse gas to the atmosphere. Large quantities (billions of tonnes) of CO2 would have to be stored for this technology to provide significant climate change mitigation. Storage of such quantities raises concern about basin-wide pressure increases and the consequences for hydrocarbon and water resources as well as land surface configuration.
The history of hydrocarbon production in California offers a reverse analog for basin-scale pressure perturbations due to industrial-scale CO2 storage. Cumulative oil production in the State, with most from the San Joaquin Basin, was 4.5 billion cubic meters (28.3 billion barrels) by the end of 2008. This is a volume equivalent to 3.1 billion tonnes of carbon dioxide (assuming a density of 0.7 tonnes/m3), which is approximately 40 times the average annual CO2 emissions from electricity generation within California from 2000 to 2006.
Oil and gas field pressures at discovery during more than a century of exploration in the San Joaquin Basin in California Oil and Gas District 4 were analyzed for time trends in the first part of a multi-year study. While the data suggest a decrease in pressure across the Basin in this District after 1968, the decrease was not significant at the 5% level. This suggests significant interfield compartmentalization of the San Joaquin reservoirs.
Such compartmentalization would limit the impact of CO2 storage-induced pressure increases beyond the target storage volume. This would come at the cost of less storage capacity. However "refilling" the pore spaces from which oil has been removed, likely commencing with CO2–enhanced oil recovery, would provide California with decades of capacity, although pore collapse has reduced this capacity in some areas.
New Temperature-Activated Travel Joint Minimizes Expansion Issues in Horizontal Thermal Applications
Authors: Schultz Roger , Cavender Travis 
Published: July 2010

Abstract
Thermal recovery methods used in the exploitation of heavy-oil and bitumen reservoirs can create severe expansion problems on liner and production tubular equipment. This is more often the case when using horizontal sandface completion configurations in steam flood, cyclic steam, and steam-assisted gravity drainage (SAGD) applications.
Many single lateral and multi-lateral horizontal heavy-oil wells are produced initially using cold heavy-oil production methodologies where liner expansion is not a concern. However, with proper up-front planning and engineering, these wells could be converted to thermal EOR producers with the addition of thermal expansion devices placed within the liner assembly when initially completed. These expansion devices are engineered to activate with elevated temperatures once the thermal operations begin and do not require mechanical activation or well intervention. Since these devices are deployed with the liner assembly, they must also be capable of handling compression, tension, and torque loading across the liner during the deployment phase.
These devices can be deployed with the slotted liner/sand screen applications or can be used with production or concentric tubing configurations. This paper will present different wellbore configurations used with various thermal recovery methods.
Expandable Completion Liners: A Comparison of Performance With Other Completion Types in the Reg and Teguentour Fields, Algeria
Authors: Mason David , Benaichaoui Farouk , John Huw , Okwelegbe Mark , Moum Terje , Harneshaug Tom , Morgan Quentin , Jones Colin , Neumann Juergen 
Published: July 2010

AbstractFour expandable completion liners (ECLs) have been run in Algeria in two fields - these are the first ECLs in Algeria, the first worldwide in gas wells and the first worldwide in multilateral wells. This paper is the first detailed benchmark study of ECL performance.All systems to date have been run in 8 ½″ hole using 5-1/2″ base pipe ECL compliantly expanded, and the installations went well.It has been possible to compare ECL performance data against a comprehensive surveillance data set for the two fields where data from existing openhole completions allow meaningful comparisons. The other completions consist largely of slotted liners and some barefoot completions. The tested production rates in each of the wells have been high relative to normal field trends; however, the predominant factor in this is the reservoir character. PBU analysis indicates that the second well has reduced Darcy skin, while it is considered unproven in the first well (more data over time is needed). There is, however, consistent evidence for a reduction in rate-dependent proportion of total skin in both wells. This is supported by other studies and a consideration of basic principles.The reduction in the rate-dependent proportion of skin has given an increase in production rate of 5-20% as compared to the computed rate from a slotted liner. This difference assumes no borehole collapse, with analyses and discussion presented of the effect on well performance should borehole collapse occur.
Rejuvenation of Trinidad’s Oropuche Field
Authors: Sinanan B. , Jagdeo H. 
Published: July 2010

Abstract
Over the last decade mature field management has been of paramount importance for economic sustainability and survival for many oil field operators. In Trinidad and Tobago, mature blocks are occasionally leased or farmed out to private operators by the state when the fields are no longer considered to be feasible investments according to state’s economic benchmarks and or operational capabilities.
The Oropuche farmout is one such field situated onshore, south Trinidad in close proximity to the western coastline. In 2007, API Pipeline Construction Company Limited acquired the acreage in 2007 with the production of approximately 60 bopd from 22 wells. This privately owned company was challenged to increase production from existing producers and increase reserves using modern reservoir management practices. Since then the operator had increased production to approximately 300 bopd, planned an eight well infill drilling program and proposed enhanced oil recovery projects. Significant cost has been incurred thus far and more expenditure is expected as projects are phased in. The operator conducted a geotechnical study as required at inception but has continued to study the field and develop new opportunities.
This paper describes the local processes and techniques used in field optimization, creation of a functional organizational structure, development of new opportunities and formulating a practical, reservoir development plan. This work details the work plan that is being adopted by the operator. The successful approach used at the Oropuche field and proposed in this document can assist many operators whoexperience various challenges associated with developing mature acreage and encouraging sustainable operations.
Molecular Design And Fractal Applications In Enhancing Oil Recovery From Low-Permeability Oil Reservoirs By Gemini Surfactant Flooding
Authors: Wei H. , Liu W. , Wei G. , Yin F. , Liu J. 
Published: July 2010

Abstract
High injection pressure and the imbalance between water injection and oil production are two of the difficulties in developing low permeability oil reservoirs. Injecting gemini surfactants is a promising technique to overcome the difficulties to enhance oil recovery from low permeability oil reservoirs. Gemini surfactants enhance oil recovery by lowering the surface tension between oil and water. Gemini surfactant A and gemini surfactant B have same hydrophilic head group and hydrophobic tail. The two surfactants have equivalent capacity of lowering the surface tension between oil and water. Gemini surfactant A enhanced oil recovery by 4%, gemini surfactant B enhanced oil recovery by more than 10%. Based on the fractal dimensions of molecular fragments, the fractal dimension of the spacer group of gemini surfactant A is different from that of gemini surfactant B. The cores of the gemini surfactants flooding formation are analyzed by the method of box counting dimension. The fractal dimension of the spacer group of a gemini surfactant is in relation to the fractal dimensions of the cores.
Gemini surfactant C is subsequently designed and the fractal dimension of its spacer group is less than gemini surfactant B. Gemini surfactant C enhanced oil recovery by more than 20%.
The fractal dimension of the spacer group of gemini surfactant A is close to 2, and the fractal dimension of the spacer of gemini surfactant B is close to 1.4. The fractal dimensions of the cores range from 1.40 to 1.84. The fractal dimension of the spacer group of a gemini surfactant should be less than the fractal dimension of the microstructure of the reservoirs. The gemini surfactants are absorbed more onto the rock surface as the spacer groups of the gemini surfactants are less complicated than the rock surface.
The fractal analyses of low permeability oil reservoirs indicate the fractal dimensions are less than 2, which means the microstructure of low permeability oil reservoirs are different from medium-high permeability oil reservoirs. The fractal analyses of molecular fragments help design more exact and efficient oilfield chemicals.
Bubble Point Pressure Empirical Correlation
Authors: Moradi B. , Malekzadeh E. , Amani M. , Boukadi F. H. , Kharrat R. 
Published: July 2010

Abstract
Bubble point pressure is an important reservoir fluid property. Ideally, Bubble point pressure is determined experimentally in the laboratory; However, this value is not always available and correlations are consequently used to determine it.
At this work, first the published bubble point pressure are reviewed and then a new correlation is developed to estimate bubble point pressure of crude oils in worldwide range.
This correlation is applicable for crude oils of ºAPI ranging between 6 to 57.
The comparison of this new correlation with other published ones shows that it is much more accurate than the other ones.
The average absolute deviation error (percent) of the new correlation is about 16.96%.
Study and Field Application of Profile Control Agent in High Temperature and High Salinity Reservoir
Authors: Dai C. , You Q. , Zhao L. F. , Xiong W. 
Published: July 2010

Abstract
Polymer gel is not suitable for profile control in high temperature and high salinity reservoir. In order to solve the problem above, a good inorganic profile control agent (Na2O·mSiO2) used in high temperature and high salinity reservoir is studied in this paper. The thermal sensitivity, salt sensitivity of sodium silicate and their influence factors in high temperature and high salinity are investigated. The blocking ability and oil displacement ability of sodium silicate in high temperature and high salinity are also investigated through physical simulation experiments. The results show that sodium silicate in high temperature and high salinity can self-generate white precipitation which can effectively block high permeability zone and or thief zone and expand sweep volume. The precipitation mass is related to modulus, temperature and aging time in high temperature; after meeting brine water, sodium silicate can also generate white precipitation and the precipitation mass is associated with modulus, salinity and temperature. Sand pack experiments indicate that sodium silicate in high temperature and high salinity has good blocking and oil displacement effect, which can further enhance oil recovery. Field application results also confirm that sodium silicate is a good inorganic profile control agent in high temperature and high salinity reservoir.
From Trondheim to Trinidad: Utilizing North Sea Technologies in the South Seas
Authors: Siggerud E. I. , Kjellesvik L. E. , Battie J. E. , McCollin R. D. , Oberkircher J. 
Published: July 2010

Abstract
The Norwegian Sector of the North Sea is renowned for the development and implementation of new technology in order to extract hydrocarbons from the earth. The combination of a cultural affinity for technology, harsh and unforgiving operating environment that stretch the limits of man and technology and high value assets combine to create the "Perfect Storm" for the application of technology. So how do you transfer this methodology to an old onshore field in Trinidad?
Fram Exploration is a company based in Trondheim; Norway that has recently been awarded a lease onshore Trinidad. The Management and staff of Fram have extensive experience in the development and implementation of new technologies in Norway and around the world. This paper will describe the methodologies and technologies that have been developed and how they will be applied to an onshore field in Trinidad. These technologies will include cutting-edge sub-surface mapping and geologic evaluation techniques as well as well construction, drilling and completion capabilities. Also included in the paper will be a description of the collaborative decision making process that will be utilized to plan and execute this field development strategy.
New Improved Oil Recovery from Heavy and Semi-Heavy Oil Reservoirs by Implementing Immiscible Heated WAG Injection
Authors: Gholamzadeh M. A. , Hashemi P. , Dorostkar M. J. 
Published: July 2010

Abstract
Only next to thermal processes used to produce heavy oil, gas injection is the second most common enhanced oil recovery process. To increase the extent of effects of the gas on the heavy and semi-heavy oils in the reservoir by gas injection, the gas is generally injected intermittently with water. This mode of injection is called Water-Alternating- Gas (WAG) method. In recent years, there has been an increasing interest in WAG process both miscible and immiscible.
In this paper, an experimental study of immiscible Heated WAG (Heated Water-Alternating-Heated Gas) injection into a sand pack is presented for the first time. This new method is a combination of WAG and thermal process and can be used to produce heavy and semi-heavy oils from hydrocarbon reservoirs. Oil recovery efficiency resulting from Heated WAG injection was significant in comparison with unheated WAG injection. The original reservoir fluid was dead oil, and core flooding experiments were performed on it using carbon dioxide as the injection gas. In this experimental study, the sand pack was initially saturated with dead oil and irreducible formation water. A number of WAG and Heated WAG cycles with low and constant rate and, below the minimum miscibility pressure for this system were injected into sand pack alternatively.
Results of laboratory tests showed that oil recovery efficiency resulting from the immiscible Heated WAG injection is about 15% more than that of unheated WAG injection. These results also indicate that using heated water and heated CO2 instead of unheated water and CO2 can lead to interfacial tension reduction, oil swelling and viscosity reduction. Therefore, immiscible heated WAG injection can be used as an effective and feasible enhanced oil recovery method in heavy and semi-heavy oil reservoirs with significant improved results.
Prediction of Downhole Flow Regimes in Deviated Horizontal Wells for Production Log Interpretation
Authors: Bahrami Hassan , Hosseinian Armin , Rasouli Vamegh , Siavoshi Jamal , Mirabolghasemi Maryam , Sinanan Burt , Bagherian Behzad 
Published: July 2010

Abstract
Production logging is used to evaluate wells production performance. Interpretation of production log data provides velocity profile and contribution of each zone on total production. In multi-phase flow conditions, production log interpretation can be challenging since producing fluids do not have similar densities and travel with different speed depending on fluids properties and wellbore deviation.
Production log interpretation in multi-phase producing wells requires identifying downhole flow regimes and determining velocity profile for each phase. There are different flow regimes and velocity models available, which are being used in production log interpretation to determine wells flow profile in multi phase flow. However in the case of deviated horizontal intervals, the flow model might fail to provide reliable results for gas and liquids velocities.
This paper represents the use of Computational Fluid Dynamics (CFD) simulation in order to model multi-phase flow in the wellbore and evaluate velocity profile across deviated horizontal intervals. The simulation results when integrated with production log data can help estimating velocity for each phase in different flow rates and for different wellbore trajectories.
The approach can help interpretation of production logging data in horizontal multi-phase producing wells, as it can predict downhole flow regimes and identify the intervals having chance of downhole liquids re-circulation. Production logging data in a gas-oil producing deviated horizontal well with water loading in wellbore was used to verify reliability of the numerical simulation. The approach could help to evaluate the well production performance with less uncertainty.
Modeling of Water Coning Phenomena in a Fractured Reservoir and Design a Simulator
Authors: Moradi B. , Dastkhan Z. , Roozbehani B. , Montazeri G. H. 
Published: July 2010

Abstract
The problem of water production is one of the major technical, environmental, and economical issues associated with oil and gas production. It is the general accepted approach to put the well on production below a critical rate without the risk of coning.
The main goal of this study is to prepare a reservoir numerical simulator with emphasis on water coning. Present work mostly involves numerical simulation of water coning and includes proposed correlations in the literature.
The computer program included four distinct modules to calculate: critical or maximum allowable oil rate, water breakthrough time, well performance after water coning take palaces and water coning simulation. Flow equations of water and oil were discretized and numerically solved for two-dimensional coordinates. The implicit scheme was used to calculate unknown pressures of any grid block. For calculation of water saturation, explicit scheme was used.
Real field data of a well in southwest of Iran was put into the program and critical rate, water breakthrough time, well performance after water coning and water coning simulation of reservoir were determined. We found that the results of correlations are very far from the reality. On the other hand, numerical simulation shows good agreement with real production data. In addition, it was observed that the current production rate of this well would result in rapid water coning.
The critical oil rate for water-free production is important in several categories, including limiting the productive life of the oil and gas wells, separation costs, corrosion of tubular, fines migration, and hydrostatic loading.
Miscible Gas Injection Study in a Naturally Fractured Reservoir: A Case Study
Authors: Moradi B. , Tousinia H. 
Published: July 2010

Abstract
Gas injection is the most widely applied process in enhanced oil recovery (EOR) for light oils. Most of the oil production in the Middle East comes from carbonate reservoirs, the majority of which are highly fractured. Gas injection in fractured reservoirs has been used less than conventional single porosity reservoirs. Three natural phenomena of gas channeling, viscous fingering and gravity over ride jeopardize the final oil recovery in gas injection projects. In fractured reservoir due to higher vertical permeability, and strictly higher rock heterogeneity, these phenomena are more probable and this fact will challenge the feasibility of gas injection projects in fractured reservoirs.
In this work, miscible/immiscible gas injection was studied in a fractured reservoir through compositional simulation. The oil field under study is a fractured oil reservoir located in west of Iran. A homogenous DPSP (Dual Porosity-Single Permeability) synthetic model was generated which investigates the effect of molecular diffusion, displacement velocity, gas/oil fracture capillary pressure, slug size and injection pressure of injectant on final oil recovery of gas injection process. Minimum miscibility pressure (MMP) and Minimum miscibility enrichment (MME) of gas injection was determined using slim tube through compositional simulator.
Three possible scenarios – natural depletion, miscible gas injection and immiscible gas injection were compared. Results indicated that miscible injection yields better recoveries than the other, so miscible gas injection in this reservoir can be a potentially good scenario.