bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Summary
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

Abstract
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

AbstractInjecting 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

Abstract
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

AbstractX-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

ABSTRACT
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

Abstract
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.
Improved Oil Recovery from Carbonate Reservoirs by Chemical Stimulation
Authors: Xie X. , Weiss W. W. , Tong Z. , Morrow N. R. 
Published: December 2007

Abstract
Oil reserves from shallow-shelf carbonate reservoirs account for 22% of the original oil in place (OOIP) of the entire U.S. oil resource. Many of these reservoirs are naturally fractured. A pressure pulsing technique is often used in fractured fields to improve oil recovery. In some situations, imbibition of water can be promoted by chemical stimulation to alter the reservoir wettability towards water-wetness such that oil is expelled at an economic rate from the rock matrix into fractures. Class II shallow shelf carbonate reservoirs typically produce less than 10% OOIP during primary recovery and respond poorly to water injection.
In this work, promotion of imbibition was determined for a cationic surfactant, cocoalkyltrimethyl ammonium chloride, and a nonionic surfactant, an ethoxylated alcohol. Cores from three dolomitic Class II reservoirs, Cottonwood Creek, Dagger Draw, and Lustre, were used in the laboratory tests. After preparing core samples using the corresponding reservoir crude oil and brine, spontaneous expulsion of oil was measured in glass imbibition cells at elevated temperature for over 50 core samples. When reservoir brine was used as the imbibition fluid, oil recovery was in the range of 0 - 35% OOIP. After imbibition of reservoir brine had ceased, the cores were transferred into surfactant solutions at or somewhat above the critical micelle concentration to test for enhanced recovery by further imbibition. Typically, immersion in the surfactant solution resulted in additional recovery of 5 to 10% OOIP. The increased recovery is mainly ascribed to increased water wetness. The effect of acidization prior to surfactant treatment was also tested and found to be detrimental to oil recovery.