bluuebunny/crossref_metadata_2025_split huggingface dataset:
Study on Ultimate Heavy Oil Recovery From Zaqeh Field in S.W of Iran
Authors: Abolhoseini Habibollah 
Published: December 2007

Abstract
This study is about finding the best suitable secondary / tertiary oil recovery methods for the Zaqeh field which is one of the heavy oil reservoirs located in S.W of I.R.Iran. This reservoir is selected because of it's high pressure(14690 psig), high temperature(246 F), and having very deep(13895ftss) / thick pay zone(820 ft) with respect to other neighboring heavy oil reservoir(Table 1).
After reviewing the applicability of processes, the technical feasibility of each method is carried out by screening procedure based on process characteristics, reservoir and fluid properties and finally pre-designs the selected method. Based on the reservoir specification, it seems that oil recovery by primary depletion mechanism would be low (approximately 7-10%) and reservoir pressure would decline rapidly. To avoid high lifting cost and increase the reservoir oil recovery factor decision was made to use a pressure maintenance project that relies on EOR process.
After screening, it is found that the In-Situ Combustion is the applicable process for this reservoir. This selection was further approved when it compares with approximately similar reservoir (West Heidelberg in Jasper Country, journal of petroleum Tech., 1983).
By this method the ultimate oil recovery of the Zaqeh field would be reached to about 60%.
Effects of Peclet Number on Miscible Displacement Process through the Reservoir
Authors: Adewale Adeniji , Olalekan Olafuyi , Kelani Bello , Abass Ikhuoria 
Published: December 2007

Abstract
Whereas many studies have been carried out on the analysis of miscible displacement through porous media, the effects of ratio of convective mixing to the mixing due to molecular diffusion as an agent in the performance of this phenomenon have not been fully emphasized. The effects of dispersion can be simulated when viscosity ratio is favourable and there is zero gravity effect or negligible viscous-gravity ratio. This study dwells on the mathematical modeling as a qualitative tool to gain insight into the impacts of miscible displacement in improving production of oil and gas from the reservoir and the effect of dissipation due to dispersion.
The solutions to one-dimensional linear convection-diffusion equation are presented. The integral transform technique is employed to obtain solutions to the 1-D convection-diffusion equation. A FORTRAN program was employed in the process. The solutions illustrate the effects of the dimensionless variable called Peclet number in miscible displacement for different boundary conditions. The Peclet number is the ratio of convective mixing to the dispersion coefficient. At high Peclet number all solutions to the developed boundary conditions gave the same concentration profile and hence the same displacement performance to signify that displacement is due mainly to convective mixing. The displacement efficiency was discovered to have inverse relationship with the Peclet number and related directly with the square root of the injected pore volume. This study also showed the concentration profile within the medium of interest, using the above parameters as variables, and the extent of asymmetry in the resulting effluent concentration profiles.
Separator Profiling: Kuito FPSO Case Study
Authors: Lees R P 
Published: December 2007

Abstract
The Kuito field, discovered in April 1997, lies offshore Cabinda Province in Angola's deep-water Block 14, a 1,560-square-mile concession. Kuito was Angola's first deep-water oil field to come on stream in December 1999, two and a half years after discovery. Kuito oil is produced via an FPSO chartered through SBM of Monaco and Sonangol on behalf of operator ChevronTexaco.
Kuito is a heavy oil ranging from 18 - 22 API. The FPSO presently has two oil production trains with a maximum throughput of 100,000 bbls. oil per day. Three phase, horizontal, gravity separation vessels are used to separate oil and gas from unwanted produced water and solids prior to transportation. Kuito production separators were designed with traditional, single point transmitters for interface and bulk level measurement. These level transmitters were capacitance type instruments mounted inside the vessels in stilling wells. Following production start-up, separation problems began to emerge; these were manifested in numerous process upsets and shutdowns. Kuito oil can form emulsions quickly and calcium naphthenate, or ‘Kuito Gunk’ as it is referred to on the FPSO, is produced at higher temperatures and if allowed to cool solidifies. The point instrumentation was unable to detect these emulsion and naphthenate layers resulting in the instrumentation becoming fouled and ceasing to function. The separators were operated ‘blind’, utilising tri-cocks located on the side of the vessel and as the instrumentation was installed in stilling wells inside the vessel it was impossible to maintain them without shutting down and depressurising the vessels. This paper describes how nucleonic profiling instruments were retrofitted to the vessels and shows, with the aid of real time on line screen shots how operations were able to identify the different layers within the separators. This enabled oil production uptime to be increased and chemicals, emulsion breakers and defoamers, to be pro-actively dosed before the plant became unstable.
Rejuvenating Exploration in a Mature Province
Authors: Eteh Enyinnaya , Ozumba Berti 
Published: December 2007

Abstract
Although the onshore Niger Delta has been explored /exploited for hydrocarbons for the past 50 years and has begun to exhibit attributes of a mature basin, recent evaluation efforts indicate that it still has enormous potential. Kolo Creek 15.9Ma - (ca. 1000 MMBOE STOIIP), is one of several material prospects generated from the recent regional evaluation. It illustrates how a change in the Group exploration strategy triggered a change in paradigm and unleashed the full benefits of integration of regional geology and geophysics coupled with creativity.
The Kolo Creek 15.9 prospect is located in OML 28, in the Central Swamp depobelt of the Niger Delta. It is a large (ca. 23 sq km) dip rollover structure beneath the Kolo Creek field The objective stratigraphic interval (ca. 2000 ft) is a proven play. Kolo Creek, is on our STWDS for 2005.
In the study reported in this paper, high resolution sequence stratigraphy technique was applied for reservoir sand development prediction. Regional overpressure study was also carried out and the results were incorporated in the well design and rig selection.
Resulting from the study, exploration of the deep objective sequence has been planned for 2005.
Measurement of Wax Appearance Temperature of an Offshore Live Crude Oil using Laboratory Light Transmission Method
Authors: Uba Emmanuel , Ikeji Kingsley , Onyekonwu Mike 
Published: December 2007

Abstract
In subsea completions and transportation of crude oils where flowlines are on the ocean floor at less than about 5°C, knowledge of wax phase behavior of the crude is essential. Benchmark tests such as wax appearance temperature (WAT), pour point and paraffin content can be viable indicators of wax problems as the fluid may flow some considerable distance from the reservoir to the surface through cold seabed and tubing. Wax precipitation and wax related problems such as increased viscosity and pressure drops at temperatures below the cloud point must therefore be clearly identified and eliminated at the initial stages of engineering and facility design to optimize production and transportation of the crude.
In this work, a mercury-free, fully visual PVT cell equipped with a laser light transmitted solid detection system, a floating piston and a magnetically coupled impeller mixer was used to investigate WAT of an offshore Niger Delta live oil. The tests were performed at the initial reservoir conditions and at stock tank conditions. Evidence of wax precipitation of the live oil and the STO were observed. We also observed that for this particular sample that was used for the investigation, the live oil WAT was reduced by about 4°C by solution gas. This shows that for a more realistic indication of wax problems for offshore fields and subsea transportation where the sea temperature could generally be lower than STO WAT and pour point, only the STO tests may not provide realistic estimates for making live oil flow assurance related decisions. In addition, other aspects such as the amount and type of wax precipitated need to be considered before making a final decision.
EA Field Development: Intelligent Well Completion, Offshore Nigeria
Authors: Chukwueke Vincent , Constantine Jesse 
Published: December 2007

Abstract
Oil and gas reservoirs have traditionally been produced differently mainly due to fear of downhole crossflow and inability to properly allocate production to individual producing reservoirs. As a result, marginal reserves with small hydrocarbon accumulations have generally been left untapped due to economic considerations of developing such accumulations with single or multilateral wells. In the recent past, intelligent well technology has made it possible to produce such reserves commingled through a single wellbore whilst still retaining full control of each individual zone ‘remotely’ from surface and properly allocating production to each zone. Traditional barriers to general industry acceptance of intelligent well technology have been cost, reliability, and integrated functionality; but, over the past decade, the number of operators that have started to recognize the value potential of intelligent wells has grown. The evolution of intelligent well technology that can now address initial barriers and user perceptions is responsible for this increasing acceptance.
An offshore completion recently installed for Shell Nigeria illustrates how technology selection, development, along with operational excellence in planning and installation can lead to successful deployment of an intelligent well system. This paper discusses the challenges, benefits delivered and the lessons learned during the successful application of intelligent well technology in the EA field.
Dispersion Patterns Of Ground Roll (Seismic Noise) In Eastern Niger Delta
Authors: Ukaonu Cyril , Ukaigwe Francis 
Published: December 2007

Abstract
Ground roll is a collection of surface waves generated by a seismic source. The vertical component of ground roll is composed of Raleigh waves. Raleigh waves have their most natural classification in terms of dispersion patterns. All seismic waves will exhibit dispersive character in a medium which displays attenuation and the most important cause of Raleigh wave dispersion is the presence of velocity layering.
Results obtained during field seismic data acquisition with a Seismic crew of Geosource Nig Ltd has shown that the Niger Delta is not a homogeneous half-space but exhibits non-homogeneous character with unequal phase and group velocities. Hence the predominance of dispersive waves in the Niger Delta is due to its nonhomogeneous character.
The complex topographic nature of the Niger Delta give rise to scattered Raleigh waves and these can be attenuated by use of field arrays that attenuates scattered Raleigh waves from all azimuths.
Frequency - wavenumber transform of time-offset records can be interpreted in terms of Raleigh wave dispersion. This has been utilized in this study as dispersion curves of the ground roll in areas of study are presented and interpretation of ground roll dispersion patterns made with this.
This study covers the "Uti" area of Akwa Ibom state in the eastern Niger Delta and is part of an ongoing study on a more effective characterisation of ground roll in that area.
Results of this study will be very useful to seismologists, geophysicists, geologists, researchers and the academia who would like to know the ground roll properties and dispersion patterns in the Eastern Niger Delta with a view to designing attenuation strategies for it.
Beyond Beta Factors: A Complete Model for Darcy, Forchheimer, and Trans-Forchheimer Flow in Porous Media
Authors: Barree R. D. , Conway M. W. 
Published: December 2007

Abstract
The limitations of Darcy's Law to a relatively small velocity region have long been recognized. A commonly accepted approach has been to use Forchheimer's equation, and its inertial flow parameter (β), as an extension of Darcy's Law beyond the linear flow region. This "trans-Darcy" flow is especially important in hydraulic fracture conductivity calculations, where flow velocities in the proppant pack are much higher than in the surrounding reservoir. The computation and presentation of β values as functions of closure stress and permeability has become an important consideration in proppant selection and fracture treatment design.
New experimental data, under very high-rate flow conditions, has shown conclusively that Forchheimer's equation, like Darcy's Law, has a limited range of applicability. At high potential gradients the flow rate cannot be predicted from Darcy or Forchheimer equations. These data also show that β is not a single-valued function of permeability, as has been expected, but is as much a function of Reynolds Number as the apparent Darcy permeability. This leads to different values of β for the same proppant, depending on the range of flow rates used for the measurement.
This paper presents a single new equation that describes the relationship between rate and potential gradient for porous media flow over the entire range of Reynolds Number. The equation simplifies to both the Forchheimer and Darcy equations under their governing assumptions. The equation can be used to determine the correct theoretical β value and to demonstrate the limits of applicability of β and the Forchheimer equation. A new method for describing porous media flow using different coefficients, and the relationship of these coefficients to physical parameters, is presented. The development of the complete porous media flow model is supported by extensive laboratory data on various proppant packs.
Reservoir Simulation of CO2 Storage in Deep Saline Aquifers
Authors: Kumar A. , Noh M. , Pope G. A. , Sepehrnoori K. , Bryant S. , Lake L. W. 
Published: December 2007

Abstract
We present the results of compositional reservoir simulation of a prototypical CO2 sequestration project in a deep saline aquifer. The objective was to better understand and quantify estimates of the most important CO2 storage mechanisms under realistic physical conditions. Simulations of a few decades of CO2 injection followed by 103 to 105 years of natural gradient flow were done. The impact of several parameters was studied, including average permeability, the ratio of vertical to horizontal permeability, residual gas saturation, salinity, temperature, aquifer dip angle, permeability heterogeneity and mineralization. The storage of CO2 in residual gas emerges as a potentially very significant issue meriting further study. Under some circumstances this form of immobile storage can be larger than storage in brine and minerals.
Simulation Assessment of N2/CO2 Contact Volume in Coal and Its Impact on Outcrop Seepage in N2/CO2 Injection for Enhanced Coalbed Methane Recovery
Authors: Wo S. , Liang J. T. 
Published: December 2007

Abstract
Methane (CH4) production from coal beds can be enhanced by injection of either carbon dioxide (CO2) to displace or nitrogen (N2) to strip methane from coal and accelerate methane production at sustained or increased pressures. Coal has the capacity to hold considerably more CO2 than either methane or nitrogen in the adsorbed state. However, the actual field performance of enhanced methane recovery processes is largely dictated by how effectively injected gases contact and interact with coalbeds over the active project lifetime. By history matching of the nitrogen breakthrough time and nitrogen cuts in BP's Tiffany Unit, simulation revealed that the elevated pressure affected by N2 injection caused the coal fractures on the preferred permeability trends not only to expand but also to extend from injectors to producers. The early N2 breakthrough and high N2 cut indicated that the injected N2 may only contact a small portion of the total available pay. Methane seepage has already been observed from many locations along the north and west Fruitland outcrops in San Juan Basin. The concern is that injected N2/CO2 could likely follow the methane seepage paths and leak from the outcrops. Based on the geological setting of the Fruitland coal outcrop, a representative seepage model was used to simulate the effects of N2/CO2 contact volume (net pay interval) in coal and the injection distance from the outcrop on methane and N2/CO2 seepages. Under certain conditions, simulation predicted that a large volume of methane and N2/CO2 breakthrough could occur if the N2/CO2 injection wells are too close to the outcrop (within 2 miles).
Gas Injection Pilot in the Hochleiten Field
Authors: Potsch K. , Ramberger R. , Glantschnig J. , Baumgarthuber S. , Gößnitzer F. 
Published: December 2007

Abstract
The Hochleiten field, a marginal field, located in the north of Vienna, exhibits challenging features: highly compartmentalized and very viscous oil. The main reservoir horizons are at a depth of approximately 1000m. Waterflood worked only in a part of the reservoir. Poor communication and big pressure differences across the field are observed. In the screening process for accessing the bypassed oil, where consultants were included, gas injection with CO2 as the medium of choice turned out to be the most promising method. The central compartment was selected as the pilot area where so far no waterflood was tried. Initially the prognosis for the ultimate oil recovery was estimated at around 25%. EOR in the target area could gain another 5%. CO2 was injected in Huff&Puff mode, while the surrounding wells were monitored. A fault between the injection well and a neighbor well was not sealing as expected, therefore an early gas breakthrough occurred.
Information will be given on the geology, additional lab work, and the implementation in the field. The injection and production profiles of this pilot are presented. CO2 improved the inflow capacity of the injector, but the oil rates of the effected wells increased only slightly. In order to match the actual response of the reservoir, adjustment of the reservoir model became necessary. As a support for the existing reservoir description an N2 tracer test was initiated to find out the preferred communication paths.
In conclusion, the lessons learned are presented and discussed. Crucial points in the project were: reservoir description, data preparation, interaction with consultants and monitoring.
A Visual Micro-Model Study: The Mechanism of Water Alternative Gas Displacement in Porous Media
Authors: Feng Qing-xian , Di Lian-cheng , Tang Guo-qing , Chen Zhi-yu , Wang Xiao-lin , Zou Jia-xi 
Published: December 2007

Abstract
Water-alternating gas (WAG) displacement is a pronounced technique to improve gas or/and water injection in heterogeneous reservoirs. For the last half century it has been successfully applied to more than 60 oilfields worldwide. However, its mechanism still deserves further investigation. In this work, a series of water, gas, and WAG displacement studies were conducted with a sets of glass micro-models which were reproduced from a target reservoir rock by copying the pore structure images into the glass media. The pore size and geometry structure of the glass micro-model are very similar to the original. The proceeding of WAG displacement was video tape recorded versus time so that the kinetic saturation to each phase in the porous media can be obtained though a PC based image analyzer. Corroborated with the measured pressure drop across the model, the effect of WAG on mobility control is systematically studied.
The results show that the mechanism of WAG flow in porous media is much different from two phase (gas-oil and water-oil) flow. For water displacing oil, a piston-like displacement mainly occurred in the small pores (assisted with capillary pressure) and a non piston-like displacement mainly occurred in large pores. For gas displacing oil, the piston-like displacement occurred in both large and small pores as long as the viscous forces can overcome the capillary force. In general, the piston-like displacement gives a higher displacement efficiency than non piston-like displacement. Channeling of displacing phase (water or gas) caused by heterogeneous feature of the pore media was observed. However, when three phase (water-gas-oil) flow is involved, the mechanism of displacement is changed. The oil phase becomes intermediate wetting, and the gas becomes non-wetting phase and water phase remains a wetting phase. Water phase prefer to occupying the small pores due to capillary effect, while the gas prefer to occupying the large pores. The oil phase presents in the porous media in a discontinuous status; the feature of oil flow is mainly in the form of oil slug or oil film at the interfaces between water and gas phases. Accumulation and expansion of gas phase from the large pores expel the oil phase into down stream. With the proceeding of WAG displacement, the oil slug becomes smaller and finally turns into oil film; the residual oil saturation in average after WAG displacement is less than 20% OOIP, benefited from a reduced size of oil drop. It is found that pore geometry has a significant effect on residual oil saturation. "Snap off " effect plays a very important role to cut off the oil slug into oil blobs and form gas bubbles during WAG displacement. Increase in cycles of WAG tends to reduce residual oil saturation. Oil blobs trapped in very tiny pores, pore corners, and dead pores are the main type of the residual oils. At the last, an optimal WAG project to the target reservoir will be presented.
Lessons From Trinidad's CO2 Immiscible Pilot Projects 1973-2003
Authors: Mohammed-Singh Lorna J. , Singhal Ashok K. 
Published: December 2007

Abstract
Four (4) immiscible Carbon Dioxide (CO2) pilot floods were implemented between 1973 to 1990 in the Petroleum Company of Trinidad and Tobago's (Petrotrin's) reservoirs at its Forest Reserve and Oropouche fields, Trinidad. CO2 was sourced from an ammonia plant and piped twenty-five (25) miles to the fields. The projects were conducted in a gravity stable mode after primary, secondary and tertiary production (after natural gas and water injection). CO2 was injected into thick sands of variable continuity containing medium gravity crude (17 to 29° API).
Production increases were observed in all projects. Injected CO2 probably swelled the oil, reduced viscosity and helped form oil banks that could move easier under gravity. Oil production rates and recovery improved as a consequence. In some of the projects, these beneficial effects continued for many years even after discontinuation of CO2 injection (supply interruptions) aided by water influx. Interruptions in CO2 supply did not seem to harm incremental oil recovery materially. Channeling was observed at high injection rates and promoted in reservoirs with low transmissibility.
Oil recovery improved as more offtake (production) wells were added downstream of the injection wells. This reinforced the importance of optimizing volumetric sweep, and of capture during CO2 flooding by judiciously selecting injection and offtake locations. Incremental recovery ranges between 2 to 8% of the Original Oil in Place (OOIP) with predicted ultimate recoveries of 4–9% of the OOIP. Cumulative CO2 utilizations improved with efficient production practices and range from 3–11 Mcf/bbl to date.
Exploitation of similar reservoirs was indicated for increasing production/ recovery via CO2 injection. Learnings from the four (4) CO2 projects analysed can be used to define selection criteria for new CO2 injection projects and to improve management of existing projects.