bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Application of Gas Injection to Increase Recovery in a Heavy Oil Reservoir
Authors: Perry Anthony J. , Gomez M.F. 
Published: December 2007

This paper was prepared for the 96th Annual AIME Meeting to be held in Los Angeles, Calif., Feb. 19 through 23, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The I2L-3 Reservoir of the Oveja Field, Eastern Venezuela has an estimated 445 million barrels of 150 API oil-in-place.
Production history early in the operation of the reservoir pointed to a final recovery of 6.4% of the oil-in-place, or 28.5 million barrels. This figure was considerably less than that anticipated from a simple solution gas drive mechanism acting alone, 7.5% of the oil-in-place, 0 33.4 million barrels.
Individual well behavior showed this lower recovery to be mainly the result of severe water fingering, or selective encroachment of the aquifer, into successively updip outlets.
An attempt to improve upon the apparently poor depletion behavior by secondary recovery was necessary. In view of the excellent vertical permeability of the reservoir, gas availability, and the behavior of wells next to the gas cap, gas injection was recommended.
Injection commenced in August, 1961 and performance since has been very satisfactory. Gas fingering has not been a problem. The gas-oil-ratios of updip wells have been efficiently controlled by choke changes; certain wells reached by the gas-oil contact have been effectively produced at prebreak through gas-oil ratios from lowered perforations. Positive evidence of the success achieved in increasing recovery is demonstrated by the fact that water encroachment into the reservoir has been stopped. Wells which were shut-in or producing with high water cuts are now producing clean oil or producing with substantially decreased water cuts.
As of October 31st, 1966 recovery from the reservoir totaled 24.7 million barrels, or 5.6% of the oil-in-place, and the predicted recovery of 49.9 million barrels, or 11.2%, will apparently be reached.
Modeling the Effects of Trapping and Water Alternate Gas (WAG) Injection on Tertiary Miscible Displacements
Authors: Gorell S. B. 
Published: December 2007

ABSTRACT
This work investigates the effects that Water Alternate Gas (WAG) injection and trapping of oil by water have on the behavior of tertiary miscible displacements. Insights are offered into some of the trade-offs associated with the competition between improved sweep efficiency and reduced displacement efficiency associated with WAG injection. One dimensional calculations show an insensitivity of displacement efficiency to water injection over a limited range of low WAG ratios. When operating in such a manner, changing the amount of injected water has no effect on the basic solvent-oil displacement process. It only modifies what happens behind the displacement front. Mobility considerations indicate that the solvent-oil displacement is unstable. If enough water is injected with the solvent, a low mobility solvent-water bank is created which moves with the same velocity as the back of the oil bank. The WAG ratio at which these equal bank velocities occur is critical, because injection below this WAG ratio is predicted to give good displacement efficiency and poor sweep, while above this ratio mobility control and increased sweep efficiency will result at the expense of reduced displacement efficiency. In theory, injection at this "equal velocity" WAG ratio should give the benefits of both, good sweep efficiency without a reduction in displacement efficiency due to trapping. This optimum WAG ratio is shown to be relatively insensitive to the assumed level of trapping. Detailed two-dimensional simulations confirm the unstable solvent-oil displacement below the optimum WAG ratio. Mobility control and stabilization of fingers at higher WAG ratios are also confirmed. However, if trapping is important, a corresponding decrease in displacement efficiency occurs· These two-dimensional simulations also provide insight about more correct ways to model tertiary miscible displacements with simpler models, such as a mixing parameter model.
Dynamic Fluid Saturation Profiles in the Analysis of Surfactant Flooding Core Displacement
Authors: Skauge A. , Aanonsen S. I. , Graue A. 
Published: December 2007

ABSTRACT
Mobilization of the residual oil by surfactant flooding involves a complex process not fully understood. The injected surfactant slug interacts with formation brine, oil, and the mineral surface. Usually, only the effluent production is available for analysis and history matching of the surfactant core floods. In this paper the analysis is enhanced by measuring the in situ saturation profiles directly during the displacement.
In order to analyse the fluid propagation during a surfactant flood, we have measured the one dimensional saturation distribution along the core as a function of time. The fluid saturation profiles are analysed by a moveable Germanium detector, measuring the radiation from a nuclear tracer added to the brine phase. The dynamics of the saturation profiles are obtanied by scanning the core several times during the displacement. The measured saturation profiles are found to correlate well with the observed effluent production.
We focus on the description of recovery improvement, how the local saturations are developing during the surfactant floods and how well numerical simulations match the results from the experimental displacements.
Surfactants for Mobility Control in High-Temperature Steam-Foam Applications
Authors: Muijs H. M. , Keijzer P. P. M. , Wiersma R. J. 
Published: December 2007

ABSTRACT
Improvement of the steam-injection process by surfactants or foaming agents has already been demonstrated in field tests.
However, surfactants for steam-foam operations that perform well in tests at low temperatures often fail above 200 °C. Laboratory research on steam-foam processes as a means of profile modification in soak wells has been carried out with the aim of alleviating the temperature limitation.
First, the effect of surfactant structure was studied. As a result, sulphonates, both aliphatic and aromatic, were selected for further investigations. Besides critical parameters such as steam quality and surfactant concentration, the effects of a non-condensable gas and electrolyte were screened.
It was found that, for steam-mobility reduction by in-situ foam generation, surfactant concentration and molecular weight are the overriding parameters.
The thermal stability of the new products were studied in detail and the most economic supply formulation of these surfactants was identified. A product providing the best balance of all these aspects was tested in the field in soak wells on a large scale.
The data collected on surfactant structure and molecular weight make it possible to select surfactants with excellent performance combined with long-term thermal stability. This will enable a successful extension of the steam-foam process towards the more extreme temperature conditions encountered in various fields in the world.
Analysis and Explanation to Industrial Pilot Foam-Flooding Results on the Lao Jun Miao Field in China
Authors: Yang C-Z. , Huang Y-H. , Han D-K. 
Published: December 2007

Abstract
This paper describes the industrial pilot results of foam flooding for enhanced oil recovery. The results are explained by the laboratory results obtained.
Based on the experiences of the single well foam-flooding results on the Lao Jun Miao field in northwestern China, an industrial pilot foam-flooding operation was carried out in the middle of the reservoir in this field in October 1979. This pilot operation involved 18 production wells and 8 injection wells. The area of the pilot operation was 1.23 km2.
A response was obtained from a small number of the production wells, but no response was obtained from the other wells even two years later.
To analyze and explain the above-mentioned pilot results, the laboratory experiments were performed. The laboratory conditions were the same as those in the industrial pilot operation. The core sample was divided into two parts. One was swept by the conventional method, and the other was remained under its natural conditions. It was found that the precipitation occurred between the foaming agent and the water injected before the solution formed by foam with air. The amount of the precipitation depends on the concentration of the foaming agent and the salinity. The solubility of the foaming agent can be improved by adding SP-3 to the solution. The dispersion coefficient of the foaming agent (K1) between the crude oil and the formation water was equal to 1.5 in the presence of three phases. The K2 between the solid and the liquid present in four phases was greater than K1. The adsorption isotherm of the foaming agent did not correspond to that of Langmuir's model. It had a maximum value at the critical micelle concentration (C.M.C). The adsorption decreased in the presence of SP-3 and SP-6 in the foam solution.
In principle, it was found that the foam was no longer formed farther than 10 meters from the injection well.
The last part of this paper describes the results of simulation using a mathematical model. They correspond to the results of the industrial pilot and the laboratory results.
The Jobo Steamflood Project: A Preliminary Evaluation of Results
Authors: Yibirin J. G. , McGee J. H. 
Published: December 2007

ABSTRACT
This paper presents an update of "The Jobo Steamflood Project-Evaluation of Results" (1). Although an adverse condition, such as the presence of a strong natural water drive in this reservoir, which prevents pressure depletion by primary steam stimulated production, 41.5% of the STOOIP has been produced, from an estimated final recovery of 45%.
Results from this mature project include a geological description of the oil bearing formations, basic petrophysical and fluids properties, a summary of oil production/steam injection statistics, well completions including thermal insulation of steam injection wells, surface facilities and associated processes with emphasis in recent technological developments, and analysis of front tracking schemes and their results.
Since preliminary results of this project were presented (1), substantial knowledge has been gained, which is being used in the planning of commercial development of Venezuela's huge Orinoco Belt.
Performance and Operation of a Successful Polymer Flood in the Sleepy Hollow Reagan Unit
Authors: Christopher C. A. , Clark T. J. , Gibson D. H. 
Published: December 2007

ABSTRACT
The Reagan reservoir of the Sleepy Hollow Field in Red Willow County, Nebraska is an ideal polymer flood candidate. It has viscous oil in a high permeability sandstone with high oil saturation and fresh water available for injection. Laboratory and field testing were used to evaluate emulsion polyacrylamide polymers for injection. Laboratory core tests were of marginal use due to the lack of representative core samples. Fractional flow analysis was used as a screening tool and reservoir simulation studies were used to predict polymer flood performance. A field injectivity test showed the polymer to have much more effect in the reservoir than in the core tests. Based on these results, and a concern that injectivity loss could be excessive, a conservative selection was made of polymer molecular weight and solution viscosity. The polymer flood was initiated on February 14, 1985. An extensive quality control program was implemented to insure compliance of bulk emulsion shipments with specifications and to insure that fluids leaving the mixing plant and throughout the system were of suitable properties. Injected fluid properties were maintained within close tolerances and this effort contributed to the low loss in injection rate experienced in the flood. Swab-back sampling and pressure transient tests were used to measure the properties of injected fluids in the reservoir and to confirm that shear degradation losses at the sand face were not excessive. Water-oil ratios have declined from 45 to 17 in the polymer flood area, which contains 10 injectors and 45 producers. Polymer breakthrough has not been excessive and no emulsion problems have been encountered in the produced fluid system. Corrosion has increased since polymer breakthrough and there is indication of partial plugging of producing wells. Beginning in 1986, due to the downturn in oil prices, efforts were made to lower operating expenses by reducing injection rates and polymer concentration. These changes have significantly reduced operating expenses and have consequently enhanced the economics of the flood. Results to date indicate the flood will be a technical and economic success.
A Study of the Mechanism of Oil Displacement Using Water and Polymer in Stratified Laboratory Core Systems
Authors: Sorbie K. S. , Walker D. J. 
Published: December 2007

SUMMARY
Oil displacement experiments are reported which were performed in stratified rectilinear systems consisting of two lower permeability sandstone slabs, enclosing a central high permeability layer made of unconsolidated glass ballotini. The adjacent layers were in good flow communication, except for a very small region close to the outlet. This arrangement allows the crossflow mechanisms that occur when the viscosity of the displacing brine is increased by adding a water soluble polymer. These mechanisms cannot be assessed by performing experiments in one-dimensional cores or packs. Results of oil displacement experiments are presented for different mobility driving fluids, in which glycerol is used to viscosify the aqueous phase. Carbon-14 and chlorine-36 are used as radioactive tracers in the experiments. The effluent fluids from each layer were collected and analysed to produce data on the cumulative oil recovery, watercuts, flow rates in each layer, viscosities and concentrations of radioactive tracers.
The results of these oil displacement experiments were modelled using computer simulation, and a very good match to the experiments was obtained. This simulation work confirms the flow mechanisms involved when water soluble polymers are used to increase the oil production from stratified reservoirs.
Simulation of Small Chemical Slug Behavior in Heterogeneous Reservoirs
Authors: Clifford P. J. 
Published: December 2007

ABSTRACT
In simulating field performance of polymer and micellar flooding, it is frequently necessary to calculate the behaviour of chemical slugs which are small compared to the well spacing, and not much larger than the normal gridblock dimension. A polymer slug in a heterogeneous reservoir will then be subject to disruption from numerical dispersion, viscous crossflow and viscous fingering. The problem addressed in this paper is whether oil recovery from the slug can be simulated without an impracticable degree of grid refinement.
Analytical modelling is used to explain the process of slug disruption by viscous crossflow in a layered reservoir, and to demonstrate the close relationship between crossflow and oil recovery. Some of the concentration fronts will spread even in the absence of dispersion. Numerical simulation is used to examine the sensitivity of slug behaviour to grid refinement, dispersion, slug size and viscosity and viscous fingering.
It is shown how a coarsening of the gridblock structure leads to large qualitative changes in slug flow and the movements of polymer within the reservoir. However, it is also demonstrated that the quantity of incremental oil recovery is much less sensitive to numerical dispersion, over a wide range of likely slug properties. This allows a much more adequate calculation of polymer flood performance in very coarse grids than would be expected from the ratio of slug to gridblock size, and is most important in permitting practicable reservoir simulation of this EOR process.
The Role of Adsorption in High pH Flooding
Authors: Ramakrishnan T. S. , Wasan D. T. 
Published: December 2007

Abstract
The high pH flooding model presented earlier (SPE14950) is extended to include the effects of adsorption of sodium on the mineral surface. The problem is formulated by conserving various species present in the system. As in the previous model, it is presumed that the lowered interfacial tension is the cause of the improved fractional flow of the oleic phase.
The governing system of equations is solved by the generalized Riemann invariants technique. Although the formulation is an extension of the earlier work it is shown that when mineral interaction is present, composition paths (simple wave curves) are inadequate in evaluating the uniqueness of the solution as long as the injected composition lies in the optimum or over-optimum range. The problem, therefore, is solved by first deriving a differential expression for shock curves. From this expression, the notion of critical point is introduced in constructing a unique solution.
The predicted profiles and histories of the model for both secondary and tertiary stimulated recoveries are presented. A new and surprising result of the model is that for over-optimum systems chemical component adsorption could change the ultimate recovery of oil even for a continuous injection of alkali. Besides delaying the chemical front, sodium adsorption on the solid surface is seen to reduce the influence of the low (optimum) interfacial tension region in recovering oil. A major conclusion of the earlier paper that a favorable viscosity ratio ensures that the optimal region influences oil recovery is found to be true. However, the extent to which it does so is found to be reduced due to adsorption. An implication from these results is that computations specific to a system would be necessary before optimal choices of alkali and salt concentrations are made.
Reservoir Modeling To Verify Geologic and Petrophysical Data: A Case Study
Authors: Ucok H. 
Published: December 2007

ABSTRACT
Reservoir modeling was utilized for resolving the large differences in core versus open-hole log derived petrophysical data gathered during the development of the Upper Repetto Reservoir of the Santa Clara Unit. Additionally, the model was utilized to confirm the presence of a sealing fault that was thought to be crossing the reservoir in a north-south direction.
The availability of four years of historical performance at the time of the modeling study along with some pressure transient data were viewed adequate to resolve the differences in petrophysical data and also to verify the presence of a north-south crossing fault.
The petrophysical properties in question, i.e., porosity and water saturation, as well as the location and the shape of the flow barrier, were all considered to be secondary history match variables behind the relative permeability during the history matching process. The reservoir description was accepted as correct upon achievement of a good history match between the actual and predicted performances.
An excellent agreement was achieved between the measured gas and water rates in field wide and in individual wells by modest adjustments in relative permeability using a reservoir description which was based on log derived porosity and core derived water saturation values. The reservoir description also included a linear flow barrier between the two domes. Thus, in the Upper Repetto reservoir the log derived porosity (ϕ) and core derived water saturation (Sw) values were verified to be correct individually or at least in combination (in the absence of other information). This was somewhat expected, especially for the water saturation. Because of the presence of abundant conductive minerals in the formation, the large error in water saturation was believed to be associated with the log derived values.
The presence of a flow barrier again was confirmed by an excellent history match in field wide and in individual well performances, particularly in those wells that were in close proximity to the flow barrier.
Effective Application of Beam Pumping Diagnostics
Authors: Ford W. H. , Svinos J. G. 
Published: December 2007

ABSTRACT
Chevron Oil Field Research Company has developed computer programs for troubleshooting rod pumping systems. These programs are successfully applied by nontechnical personnel in field locations that cover 95% of Chevron's rod pumping wells. The key reasons for this success are management support as well as program features and unique capabilities designed to simplify technology application. The analysis program (SADA) uses the wave equation to model the rod string and an exact pumping unit kinematic model. SADA can perform downhole calculations even with a solid line dynamometer card. It can determine the existing counterbalance moment from crank and counterweight information along with the counterweight positions required to balance the unit. Crank speed variation and inertia torques can be considered without measuring motor speed. Furthermore, pump intake pressure, fluid level and net stroke can easily be determined from an interactive pump card analysis. An auxiliary program to SADA called EXPROD, employs a pattern recognition scheme and expert knowledge to interpret SADA's results and diagnose well conditions. Results of applying this technology are presented as are recommendations for effective technology transfer.