bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Reservoir Management/Characterization for Independent Operators in Mature Basins, A Case Study: South Slattery Field, Powder River Basin, Wyoming
Authors: Schoeling Lanny G. , Mark Sandra 
Published: December 2007

Abstract
A detailed geological understanding of the reservoir along with a reservoir simulation to test the reservoir description and determine the optimum recovery method is important in successful operations of mature fields. There are thousands of oil and gas fields in mature basins that have not had the benefit of detailed study by an integrated team consisting of a geologist and an engineer. Major oil companies have long adopted this practice, assisted by the latest software tools, and now small independent operators have cost-effective means to similarly help them make reservoir management decisions. South Slattery Field case study demonstrates how a geologist using sequence stratigraphic concepts and moderately priced software can develop a reservoir model, which may be further analyzed by an engineer using a reservoir simulator affordable by independent operators.
Applying new geologic concepts in mature basins may result in a better reservoir model. A company's fields may contain old maps that relied on litho-stratigraphic correlations. For the South Slattery study, the geologic model benefited greatly from using parasequences as the framework in which to delineate the reservoir compartments. This process was facilitated by software that produced effective log displays; a color fill format used in conjunction with cut-off or cross-over allowed the geologist to detect patterns that was not obvious with a simple curve display.
A cost-benefit analysis was performed for the geologic portion of the study so that the managers of small companies can judge whether the technology is affordable. Simulation was conducted utilizing BOAST III which can be obtained from the Department of Energy at very little cost. The geological description was placed in the black-oil simulator and verified with a history match on primary production. History matching utilized both geological and engineering input with reservoir parameters varied depending on data accuracy, availability, and experience. This study demonstrated that an independent could utilize an integrated team to characterize and simulate a reservoir using affordable tools; this analysis will assist in making economic decisions on the future recovery technique and operations.
In summary this paper presents 1) the methodology of geologic characterization in the Slattery Field, 2) a description of the input data needed for simulation, 3) the history matching process, and 4) results of the simulation to determine additional optimum recovery techniques.
Use of Biocatalysts for Triggering Biopolymer Gelants
Authors: Bailey S. A. , Bryant R. S. , Duncan K. E. 
Published: December 2007

Abstract
Gelled polymer systems are widely used in petroleum production to modify permeability of reservoir rock. These gel systems are injectable as low-viscosity gelants and then triggered in situ to form a gel. The use of biocatalysts to trigger the delayed gelling reaction of a biopolymer gelant was evaluated in this study. The gelant was a pH-sensitive glucan biopolymer. Two bacterial strains were isolated from lake sediment and used to trigger the gelling reaction. Both strains grew anaerobically, and were mesophilic, halotolerant, and obligately alkaliphilic. Using the biocatalysts to trigger gel formation, gelation delay time was inversely proportional to initial biocatalyst concentration and gelation could be delayed up to 12 days after mixing. Each of the bacterial strains had distinct effects on the rate of the gelling reaction and permanence of the formed gel. Data indicate that these strain-specific characteristics can be exploited to design gelled polymer systems with controlled performance properties.
The new polymer system was injected into sand-packed columns, glass bead-packed columns, and Berea sandstone cores, and then triggered in situ by the biocatalyst to form gel. Analysis of core effluent indicated that the in situ gelling reaction was complete. Brine permeability of cores was decreased by two to four orders of magnitude after treatment with the new gel system. In parallel corefloods, the biocatalyzed gel blocked flow through high permeability zones and diverted flow into low permeability zones. Permeability modification with the polymer system improved sweep efficiency and increased oil recovery over waterflooding alone.
Pore-Scale Modeling of Three-Phase Flow and the Effects of Wettability
Authors: Hui Mun-Hong , Blunt Martin J. 
Published: December 2007

Abstract
We analyze fluid configurations in a single pore for three-phase flow in mixed-wet systems. After primary drainage solid surfaces in contact with oil may alter their wettability. We consider waterflooding followed by gas injection for any possible combination of oil/water, gas/water and gas/oil contact angles. We compute capillary pressures for the different displacement processes, find the range of capillary pressures for which the various fluid configurations are stable, and obtain expressions for the fluid saturations and conductances.
We compute three-phase relative permeabilites for a bundle of tubes of different size with constant triangular cross sections. We model gas injection starting from different initial oil saturations, Soi. We show that the oil remains connected in wetting layers down to low oil saturation with a characteristic layer drainage regime. The only exceptions are non-spreading oils in water-wet media and large gas/oil contact angles. The relative permeability of the phase of intermediate wettability depends on both its own saturation and Soi, while the other relative permeabilities are functions of their own saturation only. In water-wet media, oil is the intermediate-wet phase. In weakly oil-wet media, water is intermediate-wet. In most strongly oil-wet media, gas is intermediate-wet. This contradicts the assumptions made in many empirical models that gas is always the most non-wetting phase and that its relative permeability depends only on the gas saturation. For media that contain regions of different wettabilitites, all three relative permeabilities may depend on both their own saturation and Soi.
This work indicates appropriate functional dependencies for three-phase relative permeabilities, as well as being a necessary first step towards the development of a realistic three-dimensional, three-phase predictive pore-scale model that accounts for the effects of wettability.
Rheology of Gels Used For Conformance Control in Fractures
Authors: Liu Jin , Seright R. S. 
Published: December 2007

Abstract
Because extrusion experiments in fractures are expensive and time consuming, we implemented a study of gel rheology, in hopes of correlating the results to our measurements during gel extrusion through fractures. Our study focused on a one-day-old Cr(III)-acetate-HPAM gel. The elastic modulus (G') of the gel was fairly constant for strain values up to 200%. The elastic nature was evident even at strain values over 1,000%. This finding is consistent with the ease with which these gels extrude through fractures. As the polymer concentration in the gel increased from 0.3% to 1.7%, G' increased from 4 to 115 Pa. In contrast, the viscous modulus (G") remained near 1 Pa. Thus, as expected, the elastic component became increasingly dominant (over the viscous component) as the polymer concentration increased. The temperature and frequency dependencies of the elastic modulus were characteristic of those for rubber-like materials. For gels that contained 0.5% HPAM, G' exhibited a broad maximum at ~7-8 Pa for Cr(III)-acetate concentrations between 0.02% and 0.05%.
Shear stress was fairly insensitive to shear rate. When shear rate was increased by a factor of 100,000, shear stress only increased by a factor of 10. This result was consistent with our earlier observations that the pressure gradient required to extrude a gel through a fracture was fairly insensitive to injection velocity. A log-log plot of complex viscosity versus shear rate gave a slope of −0.8. This value was very similar to that for a log-log plot of resistance factor versus injection velocity that was noted earlier during gel extrusion through fractures.
Additional work is needed to establish a correlation between gel behavior in fractures versus in a viscometer.
Direct Thickeners for Carbon Dioxide
Authors: Enick Robert M. , Beckman Eric J. , Shi Chunmei , Huang Zhihua , Xu Jianhang , Kilic Sevgi 
Published: December 2007

Abstract
Direct thickeners for dense carbon dioxide were designed and synthesized. Each thickener contained highly CO2-soluble "CO2-philic" fluorinated groups, while "CO2-phobic" functionalities promoted viscosity-enhancing intermolecular associations. Semifluorinated trialkyltin fluorides, fluorinated telechelic ionomers, fluoroacrylate-styrene copolymers and sulfonated fluoroacrylate-styrene copolymers, were soluble to at least several weight percent in dense carbon dioxide without the use of a cosolvent. Increases in solution viscosity were measured using falling cylinder viscometry.
The most promising CO2 thickener was a styrene - heptadecafluorodecylacrylate bulk-polymerized random copolymer. The optimal composition of the copolymer was about 30 mol% styrene - 70% fluoroacrylate. For example, a 29% styrene-71%fluoroacrylate copolymer increased the viscosity of liquid CO2 by a factor of 250 at a concentration of 5 wt% and a shear rate of 20 s−1 at 297K and 34 MPa. A 0.2 wt% copolymer - 99.8 wt% CO2 solution exhibited a viscosity twice that of neat CO2 at shear rates of about 3000 s−1. Greater proportions of styrene in the thickener led to decreased CO2 solubility and solution viscosity, while lower proportions of styrene resulted in greater CO2 solubility but decreased solution viscosity. Solution viscosity increased with increasing copolymer concentration, increasing pressure and decreasing shear rate.
Immiscible CO2 Flooding for Increased Oil Recovery and Reduced Emissions
Authors: Brush Randal M. , Davitt H. James , Aimar Oscar B. , Arguello Jorge , Whiteside Jack M. 
Published: December 2007

Abstract
Carbon dioxide is both the most-recognized greenhouse gas as well as the second most-used injectant in oil fields, after water. This coincidence creates the possibility of injecting previously-vented CO2 to both reduce greenhouse gas emissions and increase oil recovery. Such a project has been evaluated for the Avile reservoir of the Puesto Hernandez field, located in the Neuquen Basin in west-central Argentina. This oil field produces associated gas containing approximately 60 percent CO2, which has previously been vented. The project described below assessed the feasibility of extracting and injecting the CO2 into the field to recover additional oil using an immiscible displacement process. Following an evaluation including core floods, compositional simulation, and facilities evaluation, the process was found both to have technical and economic promise in terms of improved oil recovery, and to result in reduction of both CO2 and methane emissions, the latter being an especially potent greenhouse gas. The success of this type of project would create a unique common ground for those concerned with reducing global warming and those concerned with supplying society's energy needs.
Simulation of Light-Oil Air Injection Into Viscous-Dominated and Gravity-Stable Reservoirs
Authors: Kuhlman Myron I. 
Published: December 2007

Abstract:
Simulations of Light Oil Air Injection (LOAI) in viscous-dominated ¼ five spot models and a dipping gravity-dominated Gulf Coast salt-dome reservoir were conducted to assess performance of LOAI in Equation of State (EOS), black-oil and thermal simulators. The effect of porosity, reservoir thickness, interbedded-shale, pattern size, initial reservoir temperature, and type of gas injected were tested in the viscous-dominated model. Results indicate that lower thickness, porosity, and initial reservoir temperature reduce the predicted recovery from the thermal model. A smaller or an opposite trend was found with the other models. On the other hand, recovery from the thermal model is not affected by reduced pattern size, while it is with the black-oil and EOS models. The effect of gas expansion at high temperature is important and especially evident in the gravity-dominated salt-dome model where a circulation cell forms in the gas cap. A thermal simulator is recommended for assessing reservoir performance, unless the reservoir is especially thick, has a high temperature, and API gravity.
Gas-Steam Slug Flooding to Enhance Recovery from a Medium Heavy Oil Reservoir
Authors: Wang Deyou , Zhu Tao , Chen Demin , Bao Feng , Olsen David 
Published: December 2007

Abstract
China's Liaohe Oilfield is the country's largest heavy oil field and contains numerous smaller, individually named, reservoirs (oilfields) with oil viscosity ranging from 100 cp to over 50,000 cp. Because of pressure depletion, steam huff-n-puff (cyclic steam) has reached its economic limit in a number of the heavy oil reservoirs in Liaohe. Recently, a flue (exhaust) gas-steam slug process has been tested in an attempt to improve recovery of medium heavy oil, oil with a viscosity less than 1,000 cp. Pilot tests, which started in September 1998, used one injection well and 9 production wells. The pilot test conducted in the eastern part of Block Du-66 of Shuguang Oilfield showed encouraging results. Average oil production increased from 1.8 t/d before the test to 20 t/d after more than 65 days production, with a peak oil rate of 29.2 t/d. The water-cut dropped from 84% to 39%. Drop in watercut reduced operating and water disposal costs. Cost of the entire operation of the flue gas-steam is about half of the cost of steam generated by a boiler. This paper describes the design, construction and operation of gas-steam slug project. The economics of the project and success to date are encouraging. This has prompted application of the gas-steam process to recover lower viscosity heavy oil from other Chinese reservoirs.
Impact of Reservoir Mixing on Recovery in Enriched-Gas Drives Above the Minimum Miscibility Enrichment
Authors: Solano R. , Johns R. T. , Lake L. W. 
Published: December 2007

Abstract
Gas enrichment is an important variable to optimize oil recovery in enriched-gas drives. For slimtube experiments, oil recoveries do not increase significantly with enrichments greater than the MME. For field projects, however, the optimum enrichment may be different from the MME. The optimum enrichment is likely the result of greater mixing in reservoirs than in slimtubes. In addition, 2-D effects such as channeling, gravity tonguing, and crossflow can impact the enrichment selected.
Numerical simulation is often used to model the effect of physical mixing on oil recovery in miscible-gas floods. Unfortunately, numerical dispersion can cloud the interpretation of the results by artificially increasing the level of mixing in the reservoir.
This paper investigates the interplay between various mixing mechanisms, enrichment level, and numerical dispersion. The mixing mechanisms examined are mechanical dispersion, gravity crossflow, and viscous crossflow. UTCOMP is used to evaluate the effect of these mechanisms on recovery for different grid refinements, reservoir heterogeneities, injection boundary conditions, relative permeabilities, and numerical weighting methods including higher-order methods. For all simulations, the reservoir fluid used is a twelve-component oil displaced by gases enriched above the MME.
The results show that for 1-D enriched-gas floods, the recovery difference for enrichments above the MME increases significantly with dispersion. The trend, however, is not monotonic and shows a maximum at a dispersivity of about 3 ft. Furthermore, the trend is independent of relative permeabilities and gas trapping for dispersivities less than about 3 ft, i.e. range of possible reservoir dispersivities. For 2D enriched gas floods with slug injection, the difference in recovery generally increases as dispersion and crossflow increase. The magnitude of the recovery differences is less than for the 1-D displacements. Recovery differences for 2-D are highly dependent on relative permeabilities and gas trapping. For water alternating gas (WAG) injection, the differences in recovery increase slightly with as dispersion decreases. That is, the recovery difference is significantly greater with WAG at low levels of dispersion than with slug injection. For the cases examined, the magnitude of recovery difference varies from about 1 to 8 percent of the original oil-in-place (OOIP).
Timing of Miscible Hydrocarbon Gas Injection after Waterflooding
Authors: Jerauld Gary R. 
Published: December 2007

Abstract
This paper describes the strategy used in multi-contact miscible hydrocarbon gas injection into a relatively water-wet, low permeability, light-oil reservoir and how the behavior seen in fine-grid models can be scaled-up to yield approximately the same behavior in coarse-grid simulation.
Type pattern simulations are used to show that, along with WAG ratio and solvent slugsize, the timing of the start of gas injection is a key optimization variable. The results show that the most economic recovery occurs if very low WAG ratios are used and gas injection starts when the waterflood front is slightly past midway been injectors and producers. Starting significantly later or earlier can reduce incremental oil recovery over waterflooding by a factor of 2 or more.
Comparison of fine-grid and coarse-grid versions of type pattern models shows that oil recoveries are understated by 4% OOIP and floodrates are understated by 10% if rock relative permeability curves are used in the full field model. Pseudo relative permeability curves can be constructed to correct for these inaccuracies, but different sets of relative permeability curves are required for the near-injector cells and other portions of the reservoir.
Dehydration and Permeability of Gels Used in In-Situ Permeability Modification Treatments
Authors: Krishnan P. , Asghari K. , Willhite G. P. , McCool C. S. , Green D. W. , Vossoughi S. 
Published: December 2007

Abstract
Aqueous gels placed in oil reservoirs to reduce the permeability to water can undergo partial dehydration in which part of the water contained in the gel is expelled under an imposed pressure gradient. This paper describes a study of the dehydration behavior of a polyacrylamide-chroium acetate gel in which both oil and water were used to impose a pressure gradient on bulk gels. Bulk gels were formed in cylindrical cells. The gel was held in place by a 10-micron Teflon frit at the exit end of the cell. Brine or mineral oil at a fixed pressure was placed at the other end of the gel. Flow rates of brine exiting the frit were measured. Pressure gradients between 12 and 1130 psi/ft were imposed.
Dehydration of the gel occurred with both oil and water as the dehydrating fluids. Dehydration was characterized by the formation of a finger of the dehydrating fluid near the central axis of gel and the formation of a filter cake on the exit frit. Mass balances revealed that the amount of polymer in the filter cake was very close to the amount of polymer in the finger volume based on the initial polymer concentration in the gel. Dehydration reduced the gel volumes by 50 to 70 %. The rate and final percent of dehydration was greater when oil was used as the dehydrating fluid. Permeabilities of the filter cake and the non-dehydrated bulk gel were determined to be on the order of 1 μd for the filter cake and in the range of 0.3 to 0.8 md for the bulk gel.
Relative Permeability Modifier Preflush Fracture-Stimulation Technique Results in Successful Completion of Previously Bypassed Intervals
Authors: Brocco C. , Dalrymple E. D. , Peacock H. , Creel P. , Everett D. 
Published: December 2007

Abstract
A fracture-stimulation technique that includes an in-situ generated relative-permeability modifier (RPM) preflush has been used to tap previously bypassed reserves in an Argentina formation. The formation was reported to have high water-saturation levels. Fracture-stimulation treatments performed in similar intervals usually (1) intersect a stringer of water within the targeted interval, or (2) extend into the highly saturated areas above and/or below the interval. Water cuts as high as 60 to 70% have made production of such intervals uneconomical.
A major operator has used the new RPM polymer-based preflush (PBP) technique on more than 15 wells in an Argentina formation. Data gathered from the first 3 months of production economically justify the stimulation treatments. In many cases, the treatment has limited water production to less than 15%, and some applications have reduced water production to negligible levels. This paper discusses the job design, field application, and results of several RPM preflush treatments performed in this area between 1997 and 1999.
Improving Reservoir Maps by Using Petrophysical Properties of Shales, Mudstones, and Clay-Rich Silts
Authors: Allen Rob L. 
Published: December 2007

Abstract
Petrophysical properties of mudstones, clay-rich silts and other fine grained sediments loosely referred to as shales can provide numerous geologic characteristics to improve sand reservoir maps. Useful water salinities and rock properties caused by sedimentation may be derived from impermeable zones. Those properties often relate to and reveal depositional patterns and processes. Well log responses to shales can help to delineate reservoir components, determine depositional environments, and improve production.
Full-Scale Well Model Tests of a New Chemical Plug System for Zone Isolation in Horizontal Wells
Authors: Gomez J. A. , Mamora D. D. , Lilledal L. O. 
Published: December 2007

Abstract
In horizontal wells completed as open holes that are irregularly shaped or badly washed-out, or with slotted or preperforated liners, mechanical packers can not be used to isolate a water- or gas-producing zone. Consequently, a new method using chemical packers has been developed and tested. The method involves: (i) setting two chemical wellbore plugs in the horizontal section to straddle the problem zone, (ii) squeezing gel into the problem zone, and (iii) cleaning out the borehole prior to production. Using coiled tubing, the whole operation would be conducted in one roundtrip.
The new method was tested using a 60 ft. long horizontal-well apparatus consisting of an outer 12-3/4 in. PVC casing containing two concentric metal screens (ID's 9 in. and 6 in.). Space between the screens was packed with sand, forming a 6-inch wellbore with a 1-1/2 inch thick formation, into which a 4-1/2 inch pre-perforated liner was placed. A gel-placement tool was placed inside the liner. The tool consisted of a 1-1/2 inch tubing to spot/squeeze the formation gel, an internal % inch tubing to spot the wellbore plug, and outer rubber elements for focussed gel placement. Model temperature was set at 110°F by circulating hot water through the apparatus.
Two runs were made, each consisting of spotting a 40 ft. long K-MAX wellbore plug, followed by spotting and squeezing PERMSEAL across 20 ft. of the borehole. (From symmetry, the placements represent a dual wellbore plug each 40 ft. long straddling a 40 ft. problem zone). After the formation gel had set, the apparatus was disassembled, showing the chemical plug had completely filled the borehole, strongly adhering to the borehole surface with no slumping. The formation gel penetrated and consolidated the formation. The tests confirmed the viability of the new zone isolation method that is planned for field-testing.