bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Surfactants for CO2-Foam Mobility Control
Authors: Tsau Jyun-Syung , Heller J. P. 
Published: December 2007

ABSTRACT
The effectiveness of surfactants, for C02-foam mobility control in dolomite limestone formations, is evaluated at surfactant concentrations below their critical micelle concentra-tions (CMC). The candidate surfactants are commonly used foamants which are either nonionic or anionic types of surfactants.
The evaluation procedures to be discussed, and the data to be presented, include the determination of foamability of surfactants and foam durability of C02-foam, the measurements of adsorption parameters of surfactant onto reservoir core samples, and the measurements of C02-foam mobility in reservoir rock samples. All of the experiments except the adsorption measurements are conducted at reservoir conditions. Adsorption of surfactant onto reservoir rocks is measured using a modified drop-weight method in a direct flow-through measurement at ambient conditions.
The C02-foam activities are found to be affected by the presence of crude oil in the foam durability test. However, C02-foam mobilities are still reduced effectively inside the rock samples containing some residual oil. It is also found that an additional amount of surfactant over the surfactant concentration required for C02-foam propagation is needed to satisfy the permanent adsorption. At surfactant concentrations below the CMC, the effectiveness of mobility reduction of C02-foam as well as the amount of surfactant adsorption vary with the type of surfactant and its concentration in reservoir brine.
Through the entire evaluation procedures, the best candidate surfactant and the most suitable concentration are determined for a particular rock sample at a certain reservoir condition.The laboratory evaluation procedures can be carried out in relatively uncomplicated fashion and are applicable to different reservoir conditions.
Application of a Polymer Gel System to Control Steam Breakthrough and Channeling
Authors: Hunter B. L. , Buell R. S. , Abate T. A. 
Published: December 2007

ABSTRACT
A novel means of mitigating steam channeling and premature steam breakthrough in steamdrives has been successfully applied in the West Coalinga Field, California. A unique polymer gel system, organically crosslinked in-situ, has shown the ability to divert steam from pre-existing steam channels thus, improving areal steam sweep efficiency.
Small volumes of this specially designed polymer gel system (&lt;500 bbls [&lt;79.5 m3]) were injected in six steamdrive injection wells. The applied treatments required only a minor interruption to continuous steam injection and were performed without any interruption to project production.
Analyses of treatment performances have shown positive results in less than one month. Sustained performance of the first treated injector lasted over six months. Others have continued five months without signs of significant degradation. In treating early steam. breakthrough cases, effective polymer gel placement has reduced casing effluent (steam) rates and casing pressures. Reduced casing pressure combined with increased pumping efficiency has resulted in oil production rate increases. By reducing the volume of live steam produced out of the casing, the project thermal efficiency has been improved through increased utilization of injected heat.
Temperature observation well data have shown substantial reservoir temperature decreases two months after injecting the gel system. These data suggest a redistribution of reservoir heat thus, improved areal sweep.
Compositional Changes in Distilled, Steam-Distilled, and Steamflooded Crude Oils
Authors: Richardson W. C. , Fontaine M. F. , Haynes Stewart 
Published: December 2007

ABSTRACT
Steamflooding of heavy and especially light oil reservoirs involves steam distillation of reservoir fluids. Accurate description of the steam distillation behavior of the reservoir oil is required in evaluation of reservoirs for steamflood potential and in the numerical modeling of reservoir performance using compositional simulators. The present work describes an experimental investigation into the effect of heat and water on the properties of crude oils with emphasis on compositional changes important for steamflooding.
Four crude oils in the gravity range (13 – 33° API) have been studied by steam distillation, coreflooding, gas chromatography, and actual distillation by ASTM D-2892. Some of the products from these experiments have been further characterized by a pseudo compositional analysis, densities, and molecular weight. Extensive compositional analyses on these effluents provide an insight toward understanding the steam distillation process.
Laboratory simulated distillation closely agreed with the total boiling point measured by ASTM D-2892. Boiling fractions collected from the TBP analysis were further characterized by composition (simulated distillation) and molecular weight.
Compositional analysis of laboratory coreflood effluents in a light oil (33° API) steamflood suggests preferential efficient recovery of light and middle boiling fractions.
Improved Phase Behavior Representation for Simulation of Thermal Recovery of Light Oils
Authors: Fassihi M. R. 
Published: December 2007

Abstract
This paper describes a procedure that can be used to account for the compositional effects on phase behavior of light oils in the presence of air or flue gas. A light oil system, described by an equation of state (EOS), was used in the Amoco fully compositional model to study recovery mechanisms involved in the flue gas injection process. It was found that the interaction between the flue gas and oil contributes significantly to the production of oil and should be included in thermal simulation in some manner. The results of the compositional model were compared with another model that uses compositional dependent K-values to describe the phase distribution. The latter was accomplished by using correlations of K-values as a function of the composition of CO2 in the liquid phase. Finally, a black oil thermal simulator with constant K-values at a specific pressure and temperature was used. The fluid properties and K-values for the black oil model were obtained by matching the in-situ phase mobilities and compositions from the previous two models. The recovery responses from these three models were in close agreement, indicating that this procedure is comparable to using an EOS description.
Heat Transfer and Two-Phase Flow in Fractured Reservoirs
Authors: Mukhopadhyday Sumit , Sahimi Muhammad 
Published: December 2007

ABSTRACT
We use two- and three-dimensional, fractal and non-fractal networks of interconnected fractures as models of a fractured geothermal field, and study two-phase flow and heat-transfer in such a system. We show that a fractal fracture network is much more efficient than a non-fractal network in heat recovery from a hot matrix. Moreover, the efficiency of a geothermal reservoir is very sensitive to its structure and the location of the producing well, and there may be an optimum configuration of the producing and injection wells for extracting heat and vapor from the reservoir.
Estimation of Effective Permeabilities for Heterogeneous Reservoirs
Authors: Hatzignatiou D. G. , Reynolds A. C. 
Published: December 2007

ABSTRACT
This study investigates the effects of heterogeneities on the estimates of effective or relative permeabilities from well-test pressure data obtained from a well producing a solution-gas-drive reservoir. The heterogeneous system considered in this work is that of a two-zone composite reservoir with different absolute permeability and/or relative permeability curves in the two regions. The estimation of effective (or relative) permeability values as a function of sandface oil saturation or wellbore pressure for both drawdown and buildup tests is presented. It is shown theoretically and computationally that for the two-zone problem of this work, one usually can obtain only one of the outer zone effective (or relative) permeabilities (either oil or gas) evaluated at the sandface value of oil saturation. It is also shown that the effective permeabilities estimated from pressure drawdown or buildup data reflect, at early times, the inner zone effective permeability data, and at later times reflect the outer zone effective permeability data for the oil phase. If the initial reservoir pressure is above the reservoir bubble-point pressure then the effective oil permeability of the inner or the outer zone might be obtained from the analysis of drawdown and/or buildup pressure data.
Gravity Stable Displacement of Oil by Hydrocarbon Gas After Waterflooding
Authors: Hustad O. S. , Holt Torleif 
Published: December 2007

ABSTRACT
This paper presents experimental and simulated results from two vertical core floods. The core floods consisted of injecting equilibrium gas and separator gas from the top of the core after water flooding from the bottom, respectively.
The results show that an oil bank was formed in both experiments. When separator gas was injected, oil was also recovered by vaporization.
Compositional analysis of the produced fluids during separator gas injection shows that considerable amounts of intermediate components were produced as condensate after gas breakthrough. Significant end effects were observed in the final water saturation profiles due to capillary hold-up. Analysis of the final oil saturation in the core indicates a significant gradient due to vaporization, and greater than that modeled by the compositional simulator based on an equation of state.
Performance Analysis of Several Polyacrylamide Floods in North German Oil Fields
Authors: Maitin B. K. 
Published: December 2007

ABSTRACT
Several reservoir units in the oil fields of a North German sediment basin have been polymer-flooded since 1975. Although the reservoir brine of these units has a relatively high- original salinity, polyacrylamide solutions prepared in fresh water have been injected for enhanced recovery.
After the inplacement of the required polymer slugs, these units have been water flooded for several years and thus have a complete displacement performance history.
The producers included in these floods show distinct oil banks. The production profiles, with water cut, salinity development, and polymer concentration demonstrate the relationship between oil bank and various reservoir and project parameters.
After a brief description of different flood concepts applied during project implementation, this paper will discuss the displacement efficiency of a typical polymer flood. Well-by-well analyses of production performance confirm some basic principles of the polymer flood process
A Flexible Low-Cost Approach To Improving Oil Recovery From a (Very) Small Minnelusa Sand Reservoir in Crook County, Wyoming
Authors: Bala G. A. , Duvall M. L. , Jackson J. D. , Larsen D. C. 
Published: December 2007

ABSTRACT
The Moorcroft West Minnelusa Sand Unit is a confined reservoir that provides an ideal setting for evaluation of EOR technologies because there is minimal opportunity for off pattern operations to influence interpretation of results. The unit initially represented a marginal waterflood prospect with two wells (40 acre spacing) in the reservoir producing a total of 4 BOPD. Although unsupported by geological analysis, reservoir engineering. and fluid analysis suggested strongly that the two wells were producing from a common 805 ac-ft reservoir. Oil recovery and cash flow projections indicated that if the reservoir would respond to water injection, a polymer augmented process would markedly increase recovery. Design and installation of a multipurpose waterflood plant was staged to keep monetary investment and risk at a minimum until communication between the wells was demonstrated. In August, 1989, oil production increased from 3 to 6 BOPD demonstrating well communication. Thereafter, a skid-mounted water injection plant containing a dry solids feed system, liquid chemical storage and proportioning equipment, and a small triplex pump was installed. Polymer injection for volumetric sweep improvement was started in October 1989. An alkaline/polymer (A/P) process designed to reduce residual oil saturation was initiated in September 1991.
Enhanced Recovery From Lower Muddy Fluvial Sandstone Reservoirs of the Northern Powder River Basin, Wyoming
Authors: Goolsby J. E. , Neumiller W. P. 
Published: December 2007

ABSTRACT
This paper, in part, represents results of a study supported by North Finn, a small oil an gas producer. It includes 13 Muddy Sandstone waterfloods located in the Northern Powder River Basin of Wyoming. The value of the study to the on-going North Carson Muddy Unit Flood is also discussed.
Fluvially deposited lower Muddy Sandstone reservoirs of early Cretaceous age have never been successfully flooded in the area. Upper Muddy sandstones deposited in marine dominated environments had varying degrees of success. North Finn's proposed flood was in a lower Muddy, fluvially deposited reservoir. Detailed study of the earlier waterflood failures encouraged North Finn to take certain precautions which have led to the first successful flood of a lower Muddy Sandstone in this area.
Use of Horizontal Wells in Vertical Miscible Floods, Pembina Nisku, Alberta, Canada
Authors: Patel R. S. , Broomhall R. W. 
Published: December 2007

ABSTRACT
Esso operates fifteen reservoirs in the Pembina Nisku area, and of these, seven are being miscibly flooded (Vertical Hydrocarbon Miscible Floods). The miscible floods are now in an advanced stage of depletion. As the oil banks in these reservoirs continue to thin, solvent coning is becoming a concern and individual wells have to be choked back. The objective of drilling horizontal wells in these reservoirs is to allow us to maintain oil productivity without solvent coning and also to increase reserves by decreasing the sandwich loss.
The first horizontal well was drilled in the Pembina Nisku "K" pool in 1989. The well initially produced solvent but was successfully worked over and has now been producing at solution gas oil ratios for approximately one year. Since then, Esso Resources Canada Limited has drilled two more horizontal wells in the Pembina Nisku "M" and "Q" pools.
Horizontal Wells in a Steamdrive in the Midway Sunset Field
Authors: Carpenter D. E. , Dazet S. C. 
Published: December 2007

SUMMARY
Three horizontal wells have been drilled in a low pressure, mature steam drive at the D&E Unit of the Midway Sunset Field, Kern County, California. Simulation studies indicate that horizontal wells in thermal projects can increase recovery efficiency due to better areal sweep, accelerate production which improves the oil-steam ratio (OSR), shorten project life, and increase project profitability.
The D&E Unit was selected as a test site for horizontal wells because gravel packs were not required for sand control. Low reservoir pressures and moderately sorted, sub-rounded sands contribute to the success of slotted liner completions. The reservoir is composed of well sorted, thick turbidite sands which dip at about 45°. The first two wells were drilled at an oblique angle to dip with approximately 400’ laterals. The third well was drilled on strike with slightly more than a 700’ lateral. Radius of curvature is approximately 40'. The three wells were drilled as short radius horizontal wells due to well and lease spacing constraints. The short radius design allows the rod pump to be placed in the vertical section of the hole with minimal drawdown sacrifice. The lowest point of the laterals is 10’ above the oil-water contact. All wells are completed with slotted liners.
The three horizontal wells cost 2-3 times more than vertical wells. Oil production rates increased 2-3 times more than vertical wells in the two wells with 400’ laterals. The third well with a 700’ lateral is more prolific with 6 times the production rate of a vertical well. At this time, the wells are too immature to accurately predict ultimate recovery. This paper will discuss the drilling and completion design of the wells, steam soak data, temperature logs in the horizontal section and current production results.
Technical and Economical Performance of Horizontal Wells For Carbon Dioxide Flooding
Authors: Ammer J. R. , Enick R. M. , Flanders W. A. 
Published: December 2007

ABSTRACT
The technical performances of horizontal and vertical wells were examined for a tertiary, carbon dioxide miscible flood in a 240-acre (97 ha) area of a west Texas field using a black-oil, pseudo-miscible simulator. Although a 40 acre (16 ha), inverted five-spot pattern was used initially for both vertical and horizontal wells, the spacing was increased to 80 acres (32 ha) for the horizontal wells to maintain the miscibility pressure in the reservoir. Horizontal injection and production wells, 1,320 feet (402 m) in length, completed at the bottom of the formation, recovered 14 to 22 percent more oil than vertical wells. Economic analyses for the horizontal injectors and producers were compared to economic analyses conducted for vertical injectors and producers. Project economics were significantly effected by the capital expense for drilling new wells. The vertical wells provided the better rate of return if no new drilling- or only one new well for every six patterns was required. If horizontal wells could be drilled from existing vertical wells- or from the surface at 1.5 times the cost of vertical wells, the rate of return was comparable- or better than vertical wells requiring one new well for every three patterns. Horizontal wells drilled from the surface at twice the cost of vertical wells provided the lowest rate of return.
Nitrogen Minimum Miscibility Pressures
Authors: Sebastian H. M. , Lawrence D. D. 
Published: December 2007

Abstract
Miscible gas flooding has been used for enhanced oil recovery for many years. Considerable data exists for CO2 and enriched hydrocarbon flooding so that screening criteria can be applied to determine when miscible flooding with these gases could be successful. However, for nitrogen the data are much more sparse. Thus, previous screening tools are very imprecise. In fact, all four correlations for nitrogen minimum miscibility pressure available in the literature predicted miscibility pressures that were more than 1000 psi different from the measured value for more than a third of the data available in the literature.
This paper presents a new much more accurate correlation for nitrogen MMP. This correlation takes into account the effects of oil composition and reservoir temperature and matches all nitrogen MMP data in the literature within 750 psi. This correlation predicts that the nitrogen MMP of an oil decreases as the methane- or intermediate content of the oil increases, and that the nitrogen MMP increases as the mol weight of the oil increases. It also shows that the nitrogen MMP goes through a maximum as the temperature increases and that this maximum is a function of oil composition.
In addition, this paper summarizes available nitrogen MMP data and presents seven new data points.
Experimental Evaluation of a Single-Well Surfactant Tracer Test for a North Sea Oil Reservoir
Authors: Garnes J. M. , Kindem Erling , Skauge Arne 
Published: December 2007

ABSTRACT
The paper addresses problems related to application of a single-well surfactant test (SWST) for a North Sea oil reservoir. Waterflooding an oil production well prior to a SWST by injection of seawater will change the oil properties in the wellbore region. Injection of unsaturated water with respect to hydrocarbon gas in a formation containing a volatile oil with GOR in the range of 100-1000, will cause stripping of the oil.
The injection of cold seawater may alter the temperature in the injection zone and this effect combined with the variation of GOR with distance from the wellbore will result in gradients both in temperature and oil properties. The effect of these variations will influence the phase behavior and the performance of the surfactants as well as the tracers.
Static multiple water-oil contact experiments at reservoir conditions have been performed. These experiments were compared to dynamic core displacements in- order to quantify the stripping of the oil phase by water. The tracer partitioning and hydrolysis were measured both in static experiments and reservoir cores. The effect of GOR on tracer partitioning was also investigated.
The results reveals that the GOR of the specific oil used was reduced from 110 to 10 and the formation volume factor (Bo) from 1.34 to 1.05. The decreasing gas content in the oil changes the phase behavior of the optimized surfactant system towards a lower phase microemulsion.
The surfactant system had to be re-optimized against the stripped oil both by static phase behavior and dynamic core displacements. The effect of stripping leads to a significant change in surfactant and tracer phase behavior. In addition, due to the changes in BO, the saturation values as determined by the tracer test yields low waterflood residual oil saturations compared to expected results of a large scale waterflood.
Measurement of Polymer Retention Levels Representative of the Formation
Authors: Goodyear S. G. , Johnston J. D. , Lawless T. A. , Woods C. L. 
Published: December 2007

ABSTRACT
To assess the economic viability of a proposed polymer augmented waterflood and to design the treatment, it is necessary to determine the polymer retention level in the rock matrix.
Static adsorption experiments on crushed rock samples are unsuitable, because the crushing process may expose new sites, and mechanical entrapment of molecules in pores is not included in the measurements. Dynamic core-flooding measurements, at deep reservoir flow rates, are therefore required. However, reservoir core plugs may be contaminated by drilling muds, particularly at the ends, increasing the adsorption capacity. In this case, detailed mass balance calculations on the polymer effluent profiles may significantly overestimate retention levels in the formation.
To overcome these problems, a pyrolysis/beta scintillation counting technique has been developed. The core plug is flooded with 14C-labelled polymer. It is then disassembled and samples from the interior are crushed and pyrolysed, to convert the carbon to CO2. The 14C content of the gas is measured via beta-scintillation counting, giving the polymer retention level in the plug's interior, where face filtration and drilling mud contamination are minimised.
This paper describes the validation of the technique. The reproducibility and efficiency of the recovery are shown to be independent of the crushed particle size, over the range 50-1000 μm, the polymer retention level, over the range 1-120 μg/g, and the presence of oil at residual saturation. Finally, the retention levels deduced from a detailed mass balance calculation and subsequent pyrolysis/beta scintillation counting of samples from an uncontaminated core are compared, and found to be consistent.
This technique is recommended for the determination of polymer retention levels in the rock matrix, under as near as possible reservoir conditions, assuming that a small amount of 14C-labelled polymer is available.