bluuebunny/crossref_metadata_2025 huggingface dataset:
Lessons Learned from Static Reservoir Modelling on Complex Carbonate Fields, Onshore UAE
Authors: Gomes J. S. , Ribeiro M. T. , El Deeb M. , Silva F. P. , Bockel-Rebelle M. O. , King R. F.
Published: December 2007

Commercially available software packages used to develop geocellular models are becoming increasingly user friendly. However, workflows for data quality control, modelling procedures and evaluation of results are not always well established, tempting inexperienced users to build 3D models without the necessary rigor. The economical and technical implications of using 3D models on reservoir simulation studies, volumetrics, and field development, on the other hand, are of paramount importance.

The need to adopt methodical and systematic processes during all stages of 3D model building and dynamic simulation is now widely recognized. This paper compiles some key data flow, process flow and quality management practices. It presents the chain of activities in 3D model building and usage, highlighting critical parts of the process, rules of thumb for obtaining quality results, best practices to be adopted, pitfalls in various assumptions and some of the prevalent misconceptions.

Issues addressed include: data analysis; quality control; data density; integration of disparate data types; framework modeling; incorporation of chrono-stratigraphic zonation; fault and fracture modeling; deterministic and stochastic property modeling; depth and property uncertainty analysis; upscaling, downscaling and visualization.

Experience on large and diverse carbonate fields, in a variety of conditions and different stages of maturity, presenting different sets of data types and well densities are combined to present a summary of useful hints and best practices to other professionals involved in doing static modelling. It is emphasized that if data QC, geologic rules, mapping principles and geostatistics are not handled properly, the resulting model will be less precise, regardless of the sophistication of the software and algorithms deployed.
Study on Ultimate Heavy Oil Recovery From Zaqeh Field in S.W of Iran
Authors: Abolhoseini Habibollah
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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

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

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.
Application of the Novel Miscible Interpretation of RST Data and the WAG Pilot Results in Reservoir Simulation for Hassi Berkine South Field
Authors: Lo L. L. , McGregor D. S. , Wang P. , Boucedra S. , Bakhoukhe C.
Published: December 2007

The Hassi Berkine South (HBNS) field is an undersaturated, low-viscosity, moderate permeability oil field within the center of the Berkine Basin in Algeria (Fig 1). Discovered in January 1995, the HBNS field had first oil production in 1998 from the Trias Argilo-Greseux Inferieur (TAGI) reservoir with a reservoir development plan (RDP) of crestal, miscible gas injection and peripheral waterflood. Full-field water-alternating-gas (WAG), as a secondary recovery process, is currently under investigation for the potential increased oil recovery and higher oil rate. A 14-month miscible water-alternating-gas (MWAG) pilot program successfully provided valuable information for reservoir simulation.

This paper describes the application of WAG pilot results in reservoir simulation and the use of the novel miscible interpretation of the Reservoir Saturation Tool (RST) in history matching the observation well data. A fine-grid simulator sector model was used to simulate the WAG pilot program. The pilot observation well data were used to fine tune the reservoir model and establish the criteria for the realistic simulation tool for the full-field WAG evaluation. The technique for correcting observation well-log data to reflect the miscible displacement process was needed to history match the hydrocarbon saturations. The simulations also examined the impact of various reservoir description assumptions on predicted solvent and water behavior at the observation well. Minimum vertical layering requirement was also investigated for realistic WAG simulation.
Influence of Horizontal Section Sinuosity and Lateral Accuracy on Heavy Oil Cold Production from Close-Spaced Senlac/Winter Saskatchewan Wells
Authors: Miller K. A. , Cameron B. , Qing L. , Becker D. L. , Hayes L. A.
Published: December 2007

Horizontal well drilling for heavy oil cold production in Western Canada was initiated in 1988, and has matured to the extent that over 550 horizontal wells have been drilled into the Cummings/Dina channel trend between Senlac and Winter, Saskatchewan. A significant fraction of the more recent wells have been drilled as infills to enhance reservoir drainage. Reviews of the performance of these wells suggest drilling accuracy in all three dimensions within the horizontal section strongly affects the performance of original wells and the ability to optimize placement of infill horizontal wells between the original wells.

Horizontal trajectory control has improved significantly in the last 10 years, the latest improvement being 'inclination at the bit.' Selected wells were analyzed to determine the key factors between horizontal section sinuosity and both production rate and ultimate recovery, and the changes in the effect of these key factors over the last 10 years. Incentive and methodology for development of current flatter wells is discussed, and predictions of improved production are given.

Initial spacing in many areas was nominally 75 meters, and several areas are being infill drilled to 37.5 meter spacing to increase reservoir drainage. The heels of the infill wells are placed between the toes of the original wells to avoid expected greater oil depletion and water coning at the heels of the original wells.

Several recent infill wells encountered lost circulation and/or magnetic interference from offsetting original wells, indicating the locations of the original wells obtained from MWD data were not accurate. For subsequent infill wells gyros were run in the original wells, and the gyro-based original well locations disagreed with the MWD-based locations. This prompted an examination of existing drilling, MWD, gyro, and magnetic North positioning data and technology.

This paper discusses the theoretical and practical aspects of drilling flatter horizontal wells, establishing the locations of existing horizontal wells, and optimum placement of infill horizontal wells between the existing wells in the Senlac/Winter, Saskatchewan pools.
Hi tech Footage for IOR in mature offshore field
Authors: Singh Kharak , Mittal A. K. , Verma S. K.
Published: December 2007

The technology of horizontal, multilateral and ERD wells has come from outer edge to mainstay in redevelopment of Mumbai High. The paper focuses on the technological improvements in engineering, placement and drilling of horizontal and multilateral wells, both infill and sidetrack, to exploit the bypassed, un-swept / less depleted reserves in the heterogeneous multi-layered carbonate reservoir.

Mumbai High field, located in western continental shelf of India, is on production since 1976 and is the largest contributor to indigenous oil production. The field comprises of several pay zones of which "P" reservoir of early middle Miocene age is the major multi-layered limestone reservoir characterized with widely varying petrophysical properties. After attaining a production of about 400,000 bopd during 1985–90 the field had entered in declining phase. The problems of differential depletion and preferential water movement in the sub-layers, gas and water channeling /cusping occurred in the reservoir effecting the sweep efficiency.

Based on the re-assessment of the reservoir with updated geological model and reservoir simulation an extensive footage campaign was launched in 2001 as a "redevelopment" IOR project. During implementation, various test experiments have been conducted on on-going basis and better strategies are being evolved. With successful application of enhanced drilling technology of horizontal, multilateral and ERD wells, and particular emphasis on targeting individual layers within the "P" reservoir, the declining production trend has already been reversed in the initial implementation phase. Oil production is showing an encouraging upward trend and an additional upside of the projected reserves is becoming visible.

The paper highlights the approach followed for managing the reservoir with emphasis on absorption of emerging technologies. Analysis of gain in productivity due to new well engineering associated with layer thickness, heterogeneity and drainage pattern have also been discussed in the paper with the future scope for tapping the more difficult reserves and improving oil recovery in cost effective way through high tech wells.
Some Lessons on Application of Horizontal Wells from the Western Canadian Experience
Authors: Singhal Ashok K. , Springer Selwyn J.
Published: December 2007

Horizontal wells are usually drilled as development wells with a motivation to recover incremental oil and to accelerate production. In other words, they are meant to access and recover oil from certain locations such that 'poorly-floodable' and otherwise 'poorly-drainable' oil ultimately left behind in the reservoir, is significantly reduced. Clearly, their suitability is linked to reservoir characteristics, heterogeneity and reservoir mechanisms. In many (but not all) situations when infill wells are economically viable, horizontal wells significantly enhance return on investments. They are important to Canada as one study1 estimated potential incremental oil reserves due to horizontal wells at 450 million cubic meters (2.8 billion barrels).

A recent study of about 12,000 horizontal wells drilled in the Western Canadian Sedimentary Basin over the last decade2 revealed that an average horizontal well added reserves by roughly twice over that added by an average offset vertical well drilled in the same pools and over the same period. If the average cost of a horizontal well was also higher by a factor of two, this points to identifying situations where horizontal infill wells would be more cost-effective. It may also be pointed out that other (but earlier) studies3,4 suggested that about one out of three horizontal wells in Western Canada would not be profitable. Economic success rate for vertical development wells in the basin, on the other hand, is usually assumed to be in the 80 to 85% range.

This paper reviews many aspects of the observed success/failure of horizontal wells in different regions of Western Canadian Sedimentary Basin. It is emphasized that whereas horizontal wells offer many advantages, it may be prudent in many situations to drill vertical rather than horizontal infill wells, in view of various uncertainties about reservoir characteristics and risks involved.
A Guide to Chemical Oil Recovery for the Independent Operator
Authors: DeBons F. Eugene , Braun Ron W. , Ledoux Will A.
Published: December 2007

This paper is designed as a guide to independent operators considering advanced technology to extend the life and improve recovery in mid-continent fields. Chemical (surfactant-polymer) flooding is a way to recover additional oil after waterflooding. Based on field and laboratory experience, surfactant-polymer flooding is assumed to recover a large fraction of the remaining oil. Major factors impacting chemical flooding oil recovery and economics are identified. The magnitude and relative importance on economics of variations in these major factors are illustrated. An objective of the paper is to set practical limits on major parameters, and thereby define sets of operating and performance conditions required to make chemical flooding economical today.

This study employs a simple, reliable, and inexpensive model to predict recoverable oil resulting from application of a surfactant-based chemical flood process. The model is the same Department of Energy (DOE) Chemical Flood Predictive Model (CFPM) used in the 1984 National Petroleum Council (NPC) study1 to predict oil recovery streams. This study applies the major cost elements of chemical flooding and assumes ranges of costs for each element. Independent operators will be able to evaluate their properties for chemical improved oil recovery (IOR) potential and predict their economics. Implementation of chemical flooding will increase the life of some major U.S. fields and produce additional oil unrecoverable by waterflooding.
Field Chemical Flood Performance Comparison with Laboratory Displacement in Reservoir Core
Authors: Wyatt K. , Pitts M. J. , Surkalo H.
Published: December 2007

Field oil recovery performance of a mobility control chemical flood can be predicted by laboratory displacement tests. Four variations comparing field results with laboratory coreflood results are: 1.) A large polymer-flood pilot in S.W. Saskatchewan involving 5 injection wells and 13 production wells. 2.) An alkaline-polymer flood in Alberta with 25 wells of which 7 were injectors. 3.) A secondary application of alkaline-surfactant-polymer in a 6 production well, 1 injection well Wyoming reservoir. 4.) An alkaline-surfactant-polymer flood of 4 inverted 5-spots in a waterflooded Chinese field. The comparison of laboratory and field results is based on oil cut and oil recovery performance. Results of comparisons suggest that radial corefloods physically simulate oil recovery process in the field when properly scaled.
Preformed Particle Gel for Conformance Control: Factors Affecting its Properties and Applications
Authors: Bai Baojun , Li Liangxiong , Liu Yuzhang , Wang Zhongguo , Liu He
Published: December 2007

Injecting preformed particle gel (PG) as a fluid-diverting agent to reduce water production is an attractive new procedure designed to minimize some of the risks inherent in gel treatments based on in-situ gelling. The objectives of this paper are: (1) understand how to control PG properties by changing gelant compositions and their fraction when synthesized; (2) determine where PG can be applied and how reservoir conditions affect PG properties; and (3) outline candidate well criteria and the proper injection procedures by illustrating several field applications.

Based on laboratory experiments, the following results will show that: (1) PG strength and swelling capacity can be controlled by adjusting gelant compositions; (2) certain additives can improve PG stability at elevated temperatures (120°C); (3) increasing temperature will increase the swelling ratio and the swelling rate of PG, and increasing salinity will reduce the swelling capacity of PG and will increase PG strength; (4) the swelling capacity of PG is insensitive to pH; (5) PG is insoluble in water, but absorbs it, swelling up to 20–200 times of its original size. It is strength- and size-controlled, environment-friendly and not sensitive to reservoir minerals and formation water salinity.

Three examples from more than 200 operations were selected to show how to choose candidate wells and how to operate the injection procedures.

PG can be used as a conformance control agent to correct permeability heterogeneity for those reservoirs with fractures or channels, both of which are widely found in mature water-flooding oilfields in China.
Development of a novel waterflood conformance control system
Authors: Frampton H. , Morgan J. C. , Cheung S. K. , Munson L. , Chang K. T. , Williams D.
Published: December 2007

An Industry Consortium (BP, ChevronTexaco and Nalco Company) conducted a joint research project known as Bright Water. The goal of this project was to develop a novel, time-delayed, highly expandable particulate material that would improve the sweep efficiency of a water flood. In November 2001, the first of these water flood profile modification treatments was pumped in the Minas field, as reported in SPE 84897 (1). An overview of the development of the particulate system is given in the present paper. The polymeric "kernel" particles are capable of "popping" under the influence of temperature and time. The expanded particle can then provide resistance to fluid flow in porous media. Various properties of the kernel dispersions are summarized. Laboratory tests representative of the deployment of the product are presented to illustrate the injection, propagation and popping of the particles.

Screening criteria for application of the product are reviewed and related to product selection for the field trial.
X-Ray Computed Microtomography Studies of Disproportionate Permeability Reduction
Authors: Seright R. S. , Prodanovic Masa , Lindquist W. Brent
Published: December 2007

X-ray computed microtomography (XMT) was used to understand why a Cr(HI)-acetate-HPAM gel reduced permeability to water 80–90 times more than that to oil in strongly water-wet Berea sandstone and in strongly oil-wet porous polyethylene. During oil flow after gel placement in Berea, a 55% (average) reduction in gel volume occurred in pores of all detected size ranges, thus leading to a relatively high permeability to oil. In porous polyethylene, reduction in gel volume occurred mainly in small pores. Because the first oil injection after gel placement did not reduce gel volume to a greater extent in large pores than in small pores, the reduction in gel volume was probably caused by gel dehydration rather than by gel ripping or extrusion.

The overall Sor in Berea jumped from 18.4% before gel placement to 51% after. The greater level of trapped oil greatly restricted water flow. Before gel placement, most residual non-wetting blobs were isolated within individual pores. In Berea at Sor after gel placement, the largest residual oil blob was 122 times larger than the largest oil blob at Sor before gel placement. This high degree of connectivity for the oil phase explains the relatively high permeability to oil after gel placement. This large blob may exist because gel affinity for water limited the formation of water films that were needed to break the large oil blob into small blobs.

In porous polyethylene, the overall Sor was significantly lower after gel placement than before gel placement (0.3% versus 17.0%). Thus, oil trapping could not explain the large disproportionate permeability reduction (Frrw/Frro=89). Gel dehydration and rehydration provide a viable explanation. In particular, paths may open during oil injection by partial dehydration of the gel. During subsequent water injection, the paths could partially close when the gel rehydrates.
Improved Sweep in Bati Raman Heavy-Oil CO2 Flood: Bullhead Flowing Gel Treatments Plug Natural Fractures
Authors: Karaoguz Osman K. , Topguder Nazan N. , Lane Robert H. , Kalfa Ulker , Celebioglu Demet
Published: December 2007

This paper covers the successful pilot field application of polymer gels for reservoir conformance improvement in the ongoing CO2 injection project at Bati Raman heavy-oil field in Southeastern Turkey. Bati Raman is a naturally fractured carbonate reservoir where the heterogeneities and the unfavorable mobility ratios between CO2 and the heavy oil cause inefficient sweep of the reservoir. These conditions prompted the pilot application of a conformance improvement fracture-plugging (flowing) gel system in three wells in July 2002. Based on injection tests performed in the field, approximate treatment volumes were estimated to be on the order of 10,000 bbls for each well. Volumes actually pumped ranged from ~6,500 - ~11,000 bbls. All three of the wells showed a gradual increase in injection pressure during treatment, indicating a decrease in injectivity index as treatment progressed. During one treatment an offset producer experienced changes in fluid level consistent with rapid pressure transmission via the connecting fracture early in the treatment, with later loss of such communication. This behavior provides direct evidence of fracture plugging during treatment.

A mechanistic semi-analytical model based on previously published laboratory work (Seright, et.al) obtained a good match with the field data. The rate-pressure data were fed into the model and effective fracture widths were back calculated. Comparison of results with the FMI log findings isexplained. Gel monitor wells responses were scaled based on field data using Fetkovich type DCA. These studies enabled the incorporation of the effect of reservoir heterogeneities on the gel propagation radius so that future gel treatment design parameters could be optimized.

Pre and post-treatment CO2 injection pressures and the rates are shown in the following table: WELLPRE-GEL (7/2002)POST-GEL (7/2003)Choke Size (x/64")Inj. Pressure (psig)Inj. Rate (MMscf/d)Choke Size (x/64")Inj. Pressure (psig)Inj. Rate (MMscf/d)109123401.12105200.68116102401.14104000.70124102401.44105400.67

Sweep efficiency was increased as defined by produced oil/injected gas ratio. One year average post-gel oil rate from 19 offset producers is 720 stb/d as compared with pre-gel oil rate of 645 stb/d. Rate of increase from the treatments is thus 75 bbl/d or 12 %, which indicates a payout time of 12 months. Keeping this enlightened approach and seizing on the key concepts, 4 more CO2 injector wells are slotted for treatment in 2004 to follow up on the encouraging results.
Polymer Gels Formulated with a Combination of High and Low Molecular-Weight Polymers Provide Improved Performance for Water-Shutoff Treatments of Fractured Production Wells
Authors: Sydansk R. D. , Al-Dhafeeri A. M. , Xiong Y. , Seright R. S.
Published: December 2007

A laboratory study has shown improved performance for fracture-problem water-shutoff polymer gels that are formulated with a combination of high and low molecular-weight (Mw) polymers. These gels are intended for application to fractures or other high permeability anomalies that are in direct contact with petroleum production wells. More specifically, we focused on evaluating the mechanical strength and improved performance of these water-shutoff gels for use when exceptionally large fracture apertures or large drawdown pressures are encountered. During our study, the gels were injected into laboratory-scale fractures while the gel was in a partially formed state. The flooding-experiment study involved the placement of partially formed chromium(III)-carboxylate/acrylamide-polymer (CC/AP) gels in 1- to 4-mm (0.04- to 0.16-in.) aperture, by 2-ft-long, by 1.5-in.-height fractures where the fracture walls were 700 md unfired Berea sandstone.

During the injection of a 1.5% high Mw and 2.0% low Mw polymer gel formulation, the partially formed gel fluid exhibited an effective viscosity of roughly 500 cp during placement in a 1-mm (0.04-in.) aperture fracture, and the matured gel exhibited exceptionally good fracture-plugging characteristics. The gel withstood 52 psi total differential pressure across the fracture length (26 psi/ft pressure gradient) for 24 hrs, while permitting no detectable brine flow through the gel-filled fracture. Subsequently when the differential pressure was increased to 175 psi (88 psi/ft pressure gradient), the gel rendered a brine permeability reduction factor in the fracture of 30,000. When placed in a 4-mm (0.16-in.) aperture fracture, a 25 psi/ft critical pressure gradient was required to render first and limited brine flow through the fracture containing gel of the same composition. After exceeding the critical pressure gradient, the stabilized permeability reduction factor imparted by the gel to brine flow in the fracture was 260,000. When increasing the brine flow rate through a gel-containing 4-mm fracture from 500 to 8,000 cm3/hr (superficial velocities of 260 to 4,100 ft/d in the open fracture), the stabilized permeability reduction factor decreased from 100,000 to 39,000.

The high and low Mw CC/AP gel exhibited significant disproportionate permeability reduction (DPR) effects during oil and brine flow through gel-filled fractures. The magnitude of the DPR effect decreased with increasing flow rate (and differential pressure). The effect also decreased with increasing number of flooding cycles with brine and oil.