bluuebunny/crossref_metadata_2025 huggingface dataset:
The Generation of Reservoir Property Distributions in Cross Section for Reservoir Simulation Based on Core and Outcrop Photos
Authors: Hardy H. H.
Published: December 2007

A technique to statistically generate distributions of reservoir properties in cross section for reservoir simulation is presented. This technique is based on statistical studies of well logs and core and outcrop photos. Both horizontal and vertical statistical measurements of well logs and core and outcrop photos confirm fractional Gaussian noise (fGn) as a good model for distributing reservoir properties. A spectral density model of core photos does a good job of reproducing many core photos. This model is used to generate the cross sections of reservoir properties conditioned to well data. The cross sections are then scaled in porosity and permeability to fit into reservoir simulators. A renormalization technique called FRACTAM is used to scale permeabilities.
Three-Dimensional Conditional Simulation of Schneider (Buda) Field, Wood County, Texas
Authors: Ravnaas R. D. , Strickland R. F. , Lake L. W. , Yang A. P. , Malik Mohammad , Prezbindowski D. R. , Mairs Tom
Published: December 2007

A three dimensional conditional simulation model, integrating a comprehensive data base coupled with engineering, geological, and petrological studies, has significantly enhanced reservoir management capabilities in the Schneider (Buda) Field. Presented are the results of a series of conditional simulations of the Schneider (Buda) Field. The Schneider (Buda) Field is developed in a Buda reef complex. Porosity types change significantly between reservoir facies. A three dimensional conditional simula-tion generated using only well control points did not adequately characterize the reservoir. An intermediate two dimensional conditional simulation using additional assumptions was then generated to refine and control the final three dimensional conditional simulation. The resulting three dimensional conditional simulation delin-eates permeability distributions that better: 1) represent the calculated heterogeneity, 2) match the available core data, and 3) model the geologic characterization, including the defined facies. The resulting distributions have been applied to a three dimensional fluid flow simulation to better predict fluid movement through the reservoir.
Analysis of Tertiary Injectivity of Carbon Dioxide
Authors: Roper M. K. , Pope G. A. , Sepehrnoori Kamy
Published: December 2007

Tertiary carbon dioxide injectivity is not always greater than brine injectivity during an initial cycle of CO2 injection above its minimum miscibility pressure (MMP), even though CO2 has a much lower viscosity than brine. This paper goes beyond the approximate analytical models used for previous investigations by examining the effects of dispersive mixing, crossflow between layers, viscous instability and phase behavior on injectivity for reservoir-scale displacement conditions in the limit of large permeability correlation length. A more realistic and comprehensive analysis of the influence of relative permeability on injectivity that does not rely upon simplifying assumptions regarding mixing and phase behavior is also provided in the form of a systematic sensitivity study. The sensitivity calculations incorporate recently reported high-pressure two- and three-phase flow relative permeabilities measured at elevated temperature with CO2, decane, and brine in a Guelph dolomite core as a base case.

This paper compares analytical calculations with numerical results obtained using a finite-difference, compositional, equation-of-state simulator. Compositional simulations that model reservoir-scale physical dispersion and crossflow are numerically difficult to make accurately, so careful attention has been paid to this aspect of the problem. First, a numerical dispersion control scheme based upon a third-order-correct finite-difference method that has been extensively tested and compared with simple analytical solutions is used. Second, the work presented here is validated by mesh refinement studies that evaluate truncation error and demonstrate that the grid used is adequate for this purpose.

The most important conclusion is that the mixing phenomena due to dispersion, crossflow and viscous instability that simple analytical models neglect can significantly influence injectivity. The results indicate that three-phase flow of gas, oil and brine needs to be modeled and that, contrary to the conclusions of other investigators, three-phase flow effects can have important influences on injectivity, even when CO2 is injected aoove its MMP. In addition, the most sensitive relative permeability parameters for reservoir-scale, tertiary CO2 flooding conditions in the presence of correlated permeability heterogeneity are identified. Sensitivity to the relative permeability parameters can also be substantial, even at low permeability contrast. The results presented in this paper are particularly pertinent to the hybrid-WAG displacement process since they provide information about the first cycle of CO2 injection.
Permian Basin Operators Seal Casing Leaks With Small-Particle Cement
Authors: Lizak K. F. , Zeltmann T. A. , Crook R. J.
Published: December 2007

Permian Basin operators who need to seal casing leaks to pass Texas Railroad Commission mechanical integrity tests have successfully applied small particle-sized cements, which penetrate casing cracks and very small channels to effect a seal.

Small casing leaks plague injection operations when integrity testing results in pressure bleedoff, which indicates presence of leaks. A batch-mixed volume of 25 to 75 sacks of fine particle cement is the typical application used to seal these leaks. There are some critical steps that must be taken to help ensure job success; these are discussed. The paper also presents a discussion of small particle-size cements, including accounts of laboratory testing. Case histories describing techniques of casing leak repair with small particle cements are recounted.
Improved Cementing Operations: A Field Study
Authors: Calvert D. G. , Webster W. W. , Lafleur K. K.
Published: December 2007

In its continuing effort to improve overall cementing job guality and results, Mobil Oil has been involved in all facets of cementation. In this endeavor, it was long recognized that conventional type cementing heads have inherent limitations and restrictions that require job interruption to drop plugs. This is known to cause or enhance (1) interruption in placement flow regimes, (2) sticking of pipe, (3) interruption of pipe movement and (4) slurry composition variances.

This paper will show field examples of improved job results by elimination of these restrictions through use of a remote controlled cementing head that has the ability to launch plugs without stopping fluid flow or pipe movement.

During these field studies, it was also noted that job safety was greatly enhanced. The paper will discuss these safety aspects.
Clean Air Act Title III and the Oil Industry
Authors: Frederick J. D. , Tulloh B. T.
Published: December 2007

Title III of the federal Clean Air Act Amendments of 1990 (CAAA) substantially changes the way hazardous air pollutants (HAPs) are to be regulated. These changes include many significant considerations for the oil and gas industry, despite some favorable language on the "aggregation" of emissions from oil and gas exploration and production (E&P) sources.
A Critique of Selected Case Studies in Environmental Geophysics
Authors: Wilson M. J. , Muir S. G.
Published: December 2007

The intelligent use of environmental and geotechnical engineering geophysics enhances one's understanding of site conditions in an integrated data collection program. Engineering geophysics includes a variety of analytical methods which, when calibrated with geologic and engineering data, improves the understanding of subsurface conditions. Examples of where the appropriate use of geophysical methods improved the interpretation of the data are presented.

The most commonly known use of geophysics in oil and gas operations is surface seismic reflection surveys and used for downhole electric logs in oil and gas wells used for well completion. Geophysical survey uses in environmental liability assessment are significantly varied. Geophysical surveys can be utilized to locate buried underground fuel storage tanks, drums or pipelines. Geophysical methods can be used to verify the depth to groundwater, and in some situations to assist in the definition of groundwater contamination plumes. Another important application is the post-installation due diligence evaluation of groundwater monitoring systems.

A critique of selected case studies will demonstrate strengths and limitations of the various surface and subsurface geophysical methods.
Injection Safety Valve Solutions for CO2 WAG Cycle Wells
Authors: Sides W. S.
Published: December 2007

Unlike the offshore production industry, there are presently no regulations that dictate the use of subsurface safety valves in land completions. However, due to the increase in the number of fields moving toward CO2 injection as a means of tertiary recovery and the potential for injury or environmental damage, many producers have decided to install subsurface safety valves in their CO2 injection wells.

This paper will address why these wells need to be protected, discuss the parameters that must be considered in the selection of a tubing retrievable safety system and cover the unique features of the following types of safety valves.

Surface controlled

Flapper check

Fixed choke-velocity

Variable orifice-velocity

Pressure differential operated

An injection well safety system is necessary to shut-in the well in the event of a catastrophic failure such as accidental well head damage, injection line leaks or tubing separation. A catastrophic failure would result in the release of CO2, wellbore fluids and reservoir fluids possibly containing H2S.
Using a Unique Acid-Fracturing Fluid To Control Fluid Loss Improves Stimulation Results in Carbonate Formations
Authors: White D. J. , Holms B. A. , Hoover R. S.
Published: December 2007

Achieving effective fracture lengths in carbonate formations by fracture acidizing has long been a recognized industry challenge. Severe fluid loss is generally considered a major factor limiting the effectiveness of acid fracturing treatments. A unique new acid fracturing fluid has been developed to control fluid loss. It has been tested in numerous laboratory and field studies. Test results confirm that this new fluid system improves live acid penetration in carbonate reservoirs by controlling acid fluid loss.

This paper discusses the technical basis for the development of this new fluid system. Laboratory test results are included. It also describes the results of field case histories in which the new system was successfully utilized in the Permian Basin of West Texas and the Williston Basin of North Dakota to control acid fluid loss in carbonate acid fracturing. Production comparisons show a substantial improvement in well performance from these wells following treatments that utilized this new system.
The Development of a Low-Cost Thermally Stable Polymer/Surfactant System for Steam-Sweep Efficiency Improvement
Authors: Cooke R. W. , Eson R. L.
Published: December 2007

The estimated 100 billion barrels of heavy oil reserves in the U.S. have responded well to thermal Enhanced Oil Recovery (EOR) during the past 30 years. However, in the current low price environment for heavy oil, new and novel low cost EOR methods must be developed to maintain and hopefully increase the production of heavy oil in the U.S. and throughout the world.

This paper documents the efforts of a 2-1/2 year, two phase project conducted in two areas of the Midway-Sunset field near Bakersfield, California. Successful applications of a novel high temperature stable polymer/surfactant gel system utilized in conjunction with the injection of steam and carbon dioxide have been demonstrated. This process has been tested in nine cyclic steam stimulation treatments, as well as in two continuous steam drive injectors and has shown the ability to effectively divert steam and correct the inherent inefficiencies due to steam channeling and steam override. This process utilizes a specially developed low cost, high temperature stable polymer/surfactant gel solution that holds the promise of substantially reducing the costs associated with current methods utilized to improve sweep efficiencies in thermal projects.
Surveillance of South Belridge Diatomite
Authors: Patzek T. W.
Published: December 2007

This paper illustrates the surveillance methods used in Shell's 1-1/4 and 5/8 acre (0.5 and 0.25 ha) waterfloods in the South Belridge Diatomite field: (1) computer-assisted monitoring of injection pressures and rates, (2) online databases with well tests and allocated production and injection data, (3) step pressure tests in numerous water injectors, (4) a geological database with cycle markers and directional surveys, (5) sonologs, and (6) salinity tests. Methods (1) – (4) require use of custom software to be practical.

The geometry of waterflood patterns in the Diatomite (well spacing compared with length of hydrofractures, injectors in-line with or offset from producers, and pattern orientation relative to the direction of maximum in-situ stress) influences the rate and frequency of coupling between the injectors and producers. It is shown that wells in the "direct" 1-1/4 acre patterns are less prone to coupling than the "staggered" ones because a "linkage potential" (defined in the text) is higher.

The proximity of hydrofractures in the 5/8 acre staggered patterns makes the injector-producer coupling unavoidable if the patterns do not follow the direction of maximum in-situ stress. The coupling develops in the N20°±5°E direction, probably along the cycle tops. The step pressure tests of many injectors in waterflood Phases I through III have shown that hydrofracture extensions are common and we are currently unable to predict the "correct" injection pressures for individual wells. It is concluded that to avoid reservoir damage, each injector must be controlled individually. Injection pressures can be increased with time by trial-and-error, but the injection rate must be kept below a safe limit to preclude excessive damage if the hydrofracture is extended.
New Low-Cost Resin System for Sand and Water Control
Authors: Fader P. D. , Surles B. W. , Shotts N. J. , Littlefield B. A.
Published: December 2007

Technologies for sand1,2 and water3,4 control have been developed, patented and successfully field tested in the Kern River Field, Bakersfield, California, using a modified furan resin. These chemical resin systems are stable to temperatures over 700°F, are inert to oilfield chemicals, are environmentally safe, involve very low material and placement costs, are applicable to wells with almost any downhole temperature, and require production interruptions of a few hours rather than days.
Analytical Inflow Performance Relationships for Three-Phase Flow in Bounded Reservoirs
Authors: Wiggins M. L. , Russell J. E. , Jennings J. W.
Published: December 2007

The performance of oil wells producing water during boundary-dominated flow was investigated to develop a better understanding of multiphase flow and its effects on single well performance. This understanding can assist the petroleum engineer in predicting the pressure-production behavior of oil wells producing under boundary-dominated flow conditions.

An analytical Vogel-type inflow performance relationships (TPR) was developed from the multiphase flow equations. This relationship is based on the physical nature of the multiphase flow system and contributes to a better understanding of the pressure-production behavior of an individual well. The analytical IPR was verified using simulator information for three-phase flow. The analytical IPR provides a method for the petroleum engineer to develop individual IPRs for each reservoir.
New Analysis Technique Provides Effective Fluid-Loss Coefficients
Authors: Lee W. S.
Published: December 2007

The minifrac procedure used in the oilfield services industry is a one-step procedure. The most important information one tries to obtain from minifrac testing is an effective fluid loss coefficient, CEFF, which is the average of the early time fluid loss coefficient, Cvc, and the late time fluid loss coefficient, Cw. Since Cvc could be much larger than Cw, this procedure works reasonably well only if the early fluid loss period, commonly referred to as spurt time, Ts, is short compared to the overall job time. However, since the spurt time is sometimes on the order of several minutes, which is in the same order as the minifrac pumping time, this method tends to overestimate the magnitude of CEFF, resulting in the overdesign of a job treatment when spurt time is large.

A mathematical algorithm has been developed in this paper to determine both the Cvc and Cw, TS and spurt volume, VSP from the conventional minifrac treatment such that they can be adequately used to design the full-scale treatment.
Joint Analysis of Pressue and Surface Tilt Data Improves Constraints on Interpretation of Hydraulic Fracture Growth
Authors: McDaniel B. W. , Underwood P. L. , Garvin T. R. , Wood M. D. , Hunter R. J.
Published: December 2007

Surface response to fracture growth (as measured by an array of tilt meters) is now being analyzed jointly with formation pressure response data to more accurately determine the result of fracture growth during stimulation treatments and for fracture closure after shut-in.

Previously, interpretations of fracture growth behavior during and after injection have depended primarily on observed trends of the treating pressure (or net pressure) response vs time. For some wells, this analysis is improved by prefrac pump-in tests and analysis of pressure decline following shut-in. However, as with well test analysis, determination of fracture parameters from a single pressure record in the wellbore will yield no nu nique solutions. Moreover, important parameters such as azimuth and inclination of the induced fracture plane cannot be interpreted from treating pressure data.

In recent years, determinations of fracture azimuth and dip have been achieved by fracture mapping based on measuring surface displacement with arrays of high gain tilt sensors. Now, more accurate fracture mapping can occur because the tilt data are being jointly analyzed with the net treating pressure response during the fracturing operation. This has yielded more highly constrained three dimensional projections of fracture growth and geometric parameters.

This paper will discuss such fracture mapping applications and present several field examples.
Frontiers-Exploratory or in Improved Recovery
Authors: Galloway George H.
Published: December 2007

This is a good time to talk frontiers. I doubt if many of us can think of a time when more of them seemed to forcibly impact our daily lives. Look at only a partial list, and I'm starting with things in general and not unique to this industry. Like them or not, we're crossing some frontiers in morality, in the stability or lack of it in the higher educational institutions, in space technology, in racial relations, computer sciences—You can arrange them in any order of importance you choose.

And look at the industry we're in and its new frontiers. Within the last few years and more particularly within the last one the crude oil supply characteristics for North America have gone through radical reappraisal. In addition to that frontier which is geographic, we seem to have an abnormal amount of frontiers to cross this year in political thing like the import quota, the safeguards against oil spills, and many other volatile issues with which the federal and various state governments understandably feel they must concern themselves. All of these things seem to provide a complicated environment within which to try to talk very convincingly about the future of this business we're in.

I do feel though that I probably couldn't stimulate you with anything electrifying along the lines of your symposium theme on improved recoveries, so I thought we might examine some relationships here first thing this morning that perhaps will put the problem of improved perhaps will put the problem of improved recoveries within the context of the larger problem confronting the industry. It is problem confronting the industry. It is the same on I heard stated from my earliest days of working in this oil business. Where is all the oil we will need to come from, and can we get it profitably?

Some of you may remember, others will have to take my statement on faith, that the problem was considered just as formidable twenty y ears ago as it is today, may be worse. I guess I will say at the outset that the answer is probably much the same today as it turned out to be then, and this answer is the title I selected: "Frontiers-Exploratory or in Improved Recovery." Said in simpler terms, some new things are going to turn up whether they are manifested in new places and new ways to find new sources, or whether in new places and new ways to get more oil out of the sources we have already found.
Comprehensive Evaluation and Decision-Making Analysis Techniques of Oilwell Production Operation Methods: Theoretical Models and Applications
Authors: Zhang Qi , Li Zongtian , Li Binghui , Jiang Huanbin , Son Datong
Published: December 2007

We present in this paper a complete set of theoretical models and systematic techniques for comprehensive evaluation and decision-making analysis of oil well production operation methods (POMs). They are the key components of production engineering project scheme for a reservoir block unit. As a systematic approch, our models and techniques take the reservoir geological research, reservoir engineering design, and development and production conditions as the basis, the whole reservoir or block unit as the research object (not a well only), the performance simulations of oil well production under development as the core, use the concepts of system engineering, and consider comprehensively various restricted conditions.

The main content in our techniques cover (1) a set of theoretical models for comprehensive evaluation and decision-making analysis of oil well POMs; (2) an oil well production performance simulator of every POM under various developing phases and a computation modle for technological and economical indeces; (3) an application of three-stage fuzzy-math judgement in the evaluation and analysis of POM; (4) a complete set of commertial computer softwares.

Through the practical applications of three re-References and illustrations at end of paper, presentive reservoirs in China's ZhongYuan, ShengLi and Dagang oilfields, the paper gives a detailed description of procedures of our models and techniques.
Use of Well Management Schemes for Rate Forecasts
Authors: Lo K. K. , Holden C. W.
Published: December 2007

In this paper, two well management schemes are proposed for rate forecasting of production streams under multi-level rate constraints. Each rate stream may be obtained from decline analysis, simulation or other means and may represent that from an individual well, a group of wells, or a separate field. In the first scheme, the well management problem was formulated as a linear programming (LP) problem and solved by the standard Simplex method. Although the solution is rigorous, the computer time for repeated solution of the problem over many time steps can be excessive. A second, approximate scheme was developed that gave results in close agreement with the LP results (within 5%) for most cases. In addition, this scheme reduces the computing time for a solution by about a factor of 4, which makes it more suitable for incorporation in a reservoir simulator. A computer program, based on the approximate scheme, was developed and used for predicting rates for several North Slope reservoirs. A second computer program, using the LP approach, was used to check the accuracy of the approximate scheme as well as another approximate scheme proposed in the literature.

In addition to being a stand-alone tool for rate forecasting, the approximate well management logic has been incorporated in a black-oil reservoir simulator with an explicit formulation. With this type of formulation, the well management logic ensures that the field oil rate is maximized at every time step in the simulations provided lift gas is unimportant.
Analysis of Multi-Feedpoint Geothermal Reservoirs
Authors: Schroeder R. C.
Published: December 2007

A new technique is described to analyze fluid production from geothermal reservoirs with multiple feedpoints. The analysis method can be used to determine the enthalpy and flow rates for reservoirs that are liquid in the undeveloped state but two-phase when produced. The analysis method can also be used to determine the formation or fracture properties associated with each feedpoint, such as permeability and porosity. Sample calculations are given for a well having multiple feedpoints and two-phase flow in the reservoir. The presence of non-negligible amounts of gas in the fluids is not included in this report.
Effective Maintenance Management in Production Operations
Authors: Wisdom W. L. , Gibson R. B.
Published: December 2007

When Tidelands Oil Production Company took over operation of portions of the Wilmington Field, they found field maintenance being performed in a reactive, "fire-fighting" mode. Eighty percent of work was unplanned and unscheduled. Preventive maintenance occupied less than 5% of mechanical and electrical/instrument man-hours worked. Maintenance work force productivity was low.

This paper describes how this company remedied this situation through supervisory training and implementation of a manual, and later computerized, maintenance management system. Operating in a more effective "planning/scheduling" mode, unscheduled work is now well below 20% and preventive maintenance occupies as much as 40% of mechanical and electrical/instrument man-hours. These improvements were accomplished while operating with manpower well below historical levels.
Reservoir Surveillance for the Alberta Lease, North Midway Field: Surveillance and the Total Energy Balance
Authors: Janssen L. D.
Published: December 2007

In 1989 and 1990 during the development program of the Potter sands on the Alberta lease, 21 TOW's (Temperature Observation Wells) were drilled on the 40 acre Alberta Lease in the North Midway Field for use in a high density surveillance program. Since that time, temperature surveys have been obtained from the TOW's on a monthly basis.

The temperature data was used to create temperature log profiles as well as temperature maps on various subzones throughout the Potter sand. The profiles and the maps were used to identify cold areas within the reservoir which aided the cyclic steaming policy. After identifying the cold spots in the reservoir, massive group steaming was utilized to uniformly preheat the reservoir areally and vertically prior to continuous injection.

The temperature log profiles and temperature maps were also used to identify steam movement downdip into the water column and preferential steam movement into channel sands. The temperature log profiles were integrated to calculate the average monthly reservoir temperature, fractional reservoir heat retention, average monthly temperature, and heat losses to the overburden and underburden layers.

With the data above, only two pieces of information were needed to calculate a total energy balance. These were the producing fluid heat losses and casing annular vent heat losses. Systems were installed to measure and record the data necessary to calculate these heat losses, and then, a total energy balance was calculated from the above data.
Optimizing Steamflpod Performance in Dipping Reservoirs
Authors: Kumar Mridul
Published: December 2007

A comprehensive, three-dimensional, numerical model study was conducted to optimize steamflood performance of dipping, heavy-oil reservoirs. Results show that a reduction in steam (heat) injection rate after steam breakthrough is much superior to the constant rate injection. A linear rate reduction is preferred, when rate reduction is initiated at steam breakthrough. However, if the rate reduction is started after the entire project area is covered with steam (which is the case for several existing projects), an exponential rate reduction is preferable.

A line drive configuration with rows of injectors and producers along the direction of the dip and injectors located near the downdip edge of the patten is preferred. This configuration better utilizes gravity override and drainage and recovers significant additional oil over conventional pattern drives, especially for higher viscosity oils. For confined systems, single-pattern results agree well with multi-pattern (up to six patterns in the direction of dip).
Air/O2 Fireflood: Comparison of Field-Scale Performances and Economics
Authors: Petit H. J-M. , Valentin E. P. , Desmarquest J-P.
Published: December 2007

A comparison of oxygen and air fireflooding is presented from the technical and economic points of view for three specific applications produced by in--situ combustion.

In order to evaluate the economic interest of using of oxygen instead of air, a technico–economic assessment was made of the supplying of oxygen. In the three cases examined, supplying pure oxygen at wellhead pressure is always at least as economical as air compression with an equivalent oxygen flowrate. It is all the more advantageous as the flowrate is high and the injection pressure is low in the range examined (10 to 30 MPa) and considering the development strategies used in this study. However, the difference between the two techniques is sufficiently small to take into consideration the implementation conditions and performances of each type of gas in the recovery process itself.

3D field–scale combustion simulations and analytical calculations were carried out to evaluate the real technical advantages and disadvantages of the enriched–air combustion process for three idealized applications. This study includes the effect of CO2 dissolution (O2 combustion) and the water injection strategy (wet combustion, following water drive) on the sweep efficiency.

The technical part of the paper leads to the following main conclusions: For a thin heavy–oil reservoir, it has been demonstrated that it is not possible to use air in a 6.25 ha (15.4 acres) inverted five–spot because of the air injectivity limitation. Oxygen clearly has a technical advantage in this case.On the contrary, injection of oxygen instead of air is not recommended for waterflooded or steam–stimulated shallow reservoirs.Based on results for one inverted five–spot, it has been found that scavenging of the oxygen fill–up behind the burn–front is not detrimental to the oxygen fireflood process when followed by waterflooding. By comparison with wet oxygen combustion, this technique may lead to higher recovery factors at slightly higher technical costs.Regarding the field developments examined, O2 wet combustion (simultaneous O2 and water injection) is definitely the most efficient process for deep heavy–oil reservoirs.

Finally, the various processes and injection strategies applied to the three cases examined were compared from an economic point of view, which considers O2/air production costs, recovery and field costs including the additional costs of oxygen over air (safety, cleaning, completion).

This study gives a complete determination of key O2/Air fireflood parameters for the field of application covered by the cases examined.
Experimental Comparison of Rheology Models for Drilling Fluids
Authors: Okafor M. N. , Evers J. F.
Published: December 2007

The shear stresses and frictional pressure losses that exist in a circulating system could be predicted through rheology models. This paper presents the experimental comparison of a relatively new rheology model called the Robertson-Stiff [1] model to widely used Ostwald-de Walle (Power Law) [2] and Bingham Plastic [3] models.

The models were used to predict shear stresses and frictional pressure losses in laboratory experiments using clay-water drilling fluids for flows through pipes and annuli. Two types of clay-water drilling fluids were used; one with a low yield stress and the other with a high yield stress.

The result of the research showed that the Robertson-Stiff [1] model predicted the best fit of the rheologic data for the two types of drilling fluids used. However, for fluid velocities greater than 2 ft/sce (0.61 m/sec) the frictional pressure losses predicted by the Robertson-Stiff [1] model differ from that of the Power Law [2] model by less than three percent.
Influence of Small-Scale Heterogeneities on Miscible Corefloods
Authors: Bahralolom I. M. , Heller J. P.
Published: December 2007

The behavior of miscible displacement patterns at laboratory scale is strongly affected by the structure of the porous medium. This report covers both the experimental and mathematical approaches employed to investigate the effect of small scale heterogeneity on miscible flood tests. Experimental computerized techniques have been used to measure the detailed variation in rock sample properties. The experimental results indicate that there are significant nonuniformities in permeability and porosity at small scale level. The results showed that the spatial variability of permeability and porosity values has a clear impact on the miscible displacement performance.

The interaction of the nonuniformity of rock properties and dispersion can be mathematically described by a set of isoconcentration surfaces that move through the porous rock. This paper presents the analysis of the growth and decay rates at which the irregularities of these surfaces change as a function of the spatial variability of rock properties and the fluid diffusivity. Based on the experimental and theoretical observations, the conventional one-space dimensional models of miscible displacement cannot properly describe laboratory corefloods. In this paper, a new alternative model is proposed, based on the correlation length and overall variance (the major geostatistical descriptors of the variability of rock properties). A major consideration for a proper interpretation of the impact of nonuniformity of rock properties on mixing in the porous medium is the relative importance of correlation length and core dimensions.
Measuring Minimum Miscibility Pressure: Slim-Tube or Rising-Bubble Method?
Authors: Elsharkawy A. M. , Poettmann F. H. , Christiansen R. L.
Published: December 2007

Measurements of carbon dioxide minimum miscibility pressures (MMP) using a slim tube apparatus were compared with those using a rising-bubble apparatus (RBA). MMPs were measured for twelve different oils, with gravities varying from 34° API to 51° API. The results were found to compare very well when using a specific criterion for the slim-tube MMP. Although the slim tube method is often referred to as the industry standard, there is no standard design, no standard operating procedure, and no standard criterion for determining MMPs with the slim tube. It is shown that the RBA is faster and more reliable than the slim tube for determining MMP. Bubble behavior is described for both the vaporizing and condensing gas processes.
Late Results of a Polymer Pilot Test: Performance, Simulation Adsorption, and Xanthan Stability in the Reservoir
Authors: Littmann Wolfgang , Kleinitz Wolfram , Christensen B. E. , Stokke B. T. , Haugvallstad Torunn
Published: December 2007

A polymer flood pilot project had been performed in the Eddesse-Nord sandstone reservoir (Germany) with a depth of 350 m, a temperature of 22 °C, an average permeability of about 1/μm2, and a thickness of 5 m. The clay content in the sandstone was about 10 %.

A xanthan-solution with a concentration of 800 ppm was injected from 1985 until 1988 into 2 wells. The xanthan was provided as a 2 % fermentation broth.

In mixing of the polymer and during injection of the polymer solution no severe problems were encountered. There was no plugging tendency in the wells observed, which is attributed to a thorough laboratory quality testing.

A response in the production wells occurred earlier than predicted by reservoir simulation and the incremental oil production was somewhat higher than the predicted 6 % of the- original oil in place.

Several simulation studies have been performed using 2 different numerical simulation models. Good history matches could be obtained with respect to production performance during the water flood phase and flow of tracers in the reservoir. The different salinities of the injected and the- original reservoir water were used as tracers, as well as the polymer and the formaldehyde, which was used as biocide.

Polymer was produced in significant amounts in one well. The produced xanthan as well as the xanthan that was injected were analysed for molecular weight, chemical composition, and solution properties. The xanthan molecules were also examined by electron microscopy.

The polymer project can be regarded as successful in terms of injection and production performance. Reservoir simulation results as well as laboratory studies have shown an adsorption of xanthan of 30-40 μ g/g. The xanthan produced in one well, after it had been in the reservoir for about three years, showed no degradation, neither chemical nor bacterial.
Alkaline-Surfactant-Polymer Flood of the West Kiehl, Minnelusa Unit
Authors: Meyers J. J. , Pitts M. J. , Wyatt Kon
Published: December 2007

An alkaline-surfactant-polymer flood was initiated in September 1987 in the Minnelusa Lower "B" sand at the West Kiehl Unit. Subsequent to unitization, two producing wells were drilled outside the Unit boundary. While this extended the productive geologic interpretation of the field, it did not effect the Unit interpretation of the alkaline-surfactant-polymer flood. Production from primary and chemical injection into State 31-36 through November 1991 resulted in 517,521 barrels of oil (82,279 m3) from the Unit wells, of which 456,361 barrels (72,555 m3) were from the area swept by injection into State 31-36. The two Kottraba wells (north of the Unit) have produced 180,686 barrels of oil (28,727 m3) as of November 1991. The- original average oil saturation in the gross swept area was 71.8% PV (69.0% PV in stock tank barrels). The gross swept pore volume of the Unit is 1,294,800 barrels (205,857 m3). The oil recovery efficiency in the gross swept area as of November 1991 is 51.1% OOIP. Projected ultimate production from the gross swept area is 541,158 barrels of oil (86,037 m3)- or 60.6% OOIP.

Projected ultimate production from the Unit is 602,318 barrels of oil (95,761 m3). This compares with a primary plus waterflood oil recovery estimate of 39.9% OOIP recovery for the West Kiehl Unit gross swept area. Comparison of the oil recovery efficiency of the West Kiehl with other Minnelusa waterfloods and polymer floods suggests the West Kiehl has out performed these other Minnelusa floods. Using the Slider technique, the displacement efficiencies of the areas swept by the State 32-36 and State 42-36 in the Unit and Kottraba Federal 2515 were 71.3%, 52.7% and 58.1%, respectively. Comparative efficiency factors for a waterflood in the Hamm Unit and a polymer flood in the OK Field are 28.5% and 45.6%. The West Kiehl, OK Field, and Hamm Unit are all Lower "B" Minnelusa Fields. A total of 184,794 incremental barrels of oil (29,380 m3) are projected for the Unit at an incremental cost of $393,458- or $2.13 per incremental barrel of oil ($13.40 per m3). No injected chemical production has been observed in the Unit wells- or the Kottraba wells as of November 1991. No changes in the Hall plot slopes were observed once a stable slope was achieved until water break through occurred at State 32-36. Alkali plus surfactant plus polymer was injected without damage to the Minnelusa formation.
Performance Review of a Large-Scale Polymer Flood
Authors: Weiss W. W.
Published: December 2007

In December 1980 Oryx Energy Company implemented a commercial polymerflood at their Eliasville Caddo Unit (ECU) located in Stephens County, Texas. During a 34-month period, about eight million pounds of hydrolyzed polyacrylamide polymer were injected into 54 wells. The planning and early performance of the project were detailed in paper SPE/DOE 12637. This follow-up paper reviews the injection and production response on a fieldwide basis since 1984.

Because of injectivity problems, not all patterns received equal polymer slugs. An analysis of the effect of polymer slug size by pattern on incremental oil recovery is presented and suggests that a minimum amount of polymer is required to improve recovery efficiency. The polymer content of the water produced from each well was monitored monthly through April 1986. By material balance, polymer retention in this carbonate reservoir is 50 lb/acre-ft.

An estimate of incremental oil from the commercial project was made by comparing the ECU production performance to nearby Caddo units. Another estimate was made by comparing the performance of each well prior to polymer injection to performance after polymer injection. The results of the two analytical methods is 25 bbl/acre-ft of incremental oil.
An Innovative Polymer Flooding Simulator Based on Advanced Concepts in Polymer Physics
Authors: Lecourtier Jacqueline , Rivenq Richard , Delaplace Philippe , Lemonnier P. , Hagry J. P. , Lefevre D.
Published: December 2007

Basic concepts in physics of polymer flow through porous media have been incorporated in a new three-phase three-dimensional multi-component reservoir simulator. This paper describes the main features of the model and especially the consistent set of physical laws designed to enable a complete description of polymer flooding in a large variety of field cases.

The characteristics of the macromolecules in solution and their interactions with the porous media are introduced in an- original polymer package. This package provides all the macroscopic parameters required by a numerical simulation accounting for the local properties of porous media and effects of salinity changes on all basic properties of the polymer.

The polymer package is coupled with a new three-phase multi-component simulator. Equations are written in compositional form with transport and diffusion-dispersion of any number of polymer, ion and tracer components in the water-phase. That allows to simulate the influence of industrial products of wide molecular weight distribution, with a polymer represented by several pseudocomponents of different molecular weights. Rheology, including permeability reduction and viscosity grading is treated from the local distribution of polymer components.

Competitive chromatographic effects of adsorption and pore wall exclusion which are both molecular weight dependent are included.

Simulations of laboratory polymer flooding experiments are presented together with a polymer flooding injection in a layered reservoir with polymer dissolved in an injection water having a salinity different from the brine in place. The results illustrate both the chromatographic and the salinity effects on polymer rheology. A field study is also presented.
Surfactant-Polymer Flooding with Anionic PO/EO Surfactant Microemulsions Containing Polyethylene Glycol Additives
Authors: Osterloh W. T. , Jante M. J.
Published: December 2007

We report the results of laboratory experiments designed to test the efficacy of polyethylene glycols, PEGs, in reducing the adsorption of optimized propoxy-lated/ethoxylated alkyl sulfates, PO/EO surfactants, onto clay. We also report the results of experiments designed to determine if the PEG additives can improve the cost-effectiveness of PO/EO surfactant/polymer flooding. A PO/EO surfactant blend was designed for a reservoir with a high salinity connate brine, 190 000 mg/L total dissolved solids, a moderate temperature, 117°F, and a light crude oil, 33°API.

The addition of PEG-1000 to the PO/EO surfactant microemulsion reduced the static adsorption of the surfactant on kaolinite to undetectably low levels. In dynamic adsorption experiments, the addition of PEG-1000 to the surfactant microemulsion reduced adsorption on Berea sandstone by a factor of four. Oil recoveries in Berea cores were substantially improved when PEG-1000 was added to the PO/EO surfactant microemulsion. Most importantly, high recoveries were achieved using small pore volumes of microemulsion. Based on oil recovery results and estimates of chemical prices, the microemulsion chemical cost per barrel of tertiary oil is lowered by as much as a factor of four when PEG-1000 is added to a PO/EO surfactant microemulsion.
Quantification and Optimization of Viscoelastic Effects of Polymer Solutions for Enhanced Oil Recovery
Authors: Ranjbar Mohammad , Rupp Juergen , Pusch Guenter , Meyn Ruediger
Published: December 2007

This paper presents the results of an extensive study aimed at describing the viscoelastic properties of polymer solutions for enhanced oil recovery. Using natural and artificial cores and polymer solutions with different storage factors, core floods were performed to examine the influence of viscoelasticity of polymer solutions on flow behaviour and oil recovery.

From the experimental results, it appears that beyond a critical injection rate the viscoelasticity of polymer solutions is reflected by increasing of effective viscosity. This critical injection rate is dependent on the concentration and degree of hydrolization (HPAA), molecular weight of polymers, core permeability, salinity and temperature. Therefore the viscoelastic core flow behaviour of polymer solutions can be adjusted to specific reservoir conditions by variation and optimization of these parameters.

To describe and quantify the viscoelastic effects by means of experimental results, a model based on Maxwell-Fluid-Relation is applied. Using the proposed model, the model index É can be determined, which represents the viscoelastic behaviour of polymer solutions in porous media.

It is found that not the relaxation time, but the model index É is the parameter which should used for quantifing this viscoelastic behaviour of polymer solutions in porous media.
New Methodology for Prudhoe Bay Miscible Gas Distribution
Authors: Cockin A. P.
Published: December 2007

This paper presents a new methodology, based on field performance data, for optimally distributing miscible gas to the 70 patterns under water alternating gas flood in the Prudhoe Bay Miscible Gas Project (PBMGP). In addition the new approach controls the timing of the miscible flood expansion to a further 60 waterflood patterns. The guiding philosophy of this approach is to maximize the efficient use of the miscible injectant (MI) by minimizing its wastage.

This methodology was implemented in the field in 1991 and is expected to increase by 50% the current volume of oil being mobilized by the Ml.

The projected ultimate recovery of 410 - 480 mmstb of oil from the expanded PBMGP is equivalent to the reserves of a major oil field. For comparison the PBMGP reserves are larger than most North Sea projects currently under development. For this reason it is clearly vital to effectively manage a project of this magnitude.
Application of Improved Oil Recovery in the Soviet Union
Authors: Mamedov Y. G. , Bokserman A. A.
Published: December 2007

This paper summarizes the results of field application of EOR techniques in the former Soviet Union. 175,000 barrels of incremental oil per day were produced in 1991 due to their implementation in different geological and environmental conditions. 55% of total production- or 96,500 BOPD were produced with the application of chemical methods, 64,500 BPD- or 37% were produced due to thermal and the rest - due to gas injection methods.

The hydrodynamic improved oil recovery methods based on waterflooding technique and reservoir management brought another 600,000 BPD additional oil.The future of enhanced oil production depends on wide application of both conventional and nonconventional advanced methods tested in laboratories and in field sites and provided for their high efficiency.

The outlook of wide application of EOR and IOR techniques by the years 2000 and 2010 at different economical conditions is presented.