bluuebunny/crossref_metadata_2025 huggingface dataset:
A Study of Oil Displacement by Microemulsion Systems – Mechanisms and Phase Behavior
Authors: Willhite G. P. , Green D. W. , Okoye D. M. , Looney M. D.
Published: December 2007

Microemulsions located in a narrow single-phase region on the phase diagram for the quaternary system consisting of nonane, isopropyl alcohol, Witco TRS 10-80 petroleum sulfonate, and brine were used to investigate the effect of phase behavior on displacement efficiency of the micellar flooding process. Microemulsion floods were conducted at reservoir rates in 4-ft (1.22-m) Berea cores containing brine and residual nonane. Two floods were made using large (1.0-PV) slugs. A third flood used a 0.1-PV slug followed by a mobility buffer of polyacrylamide. Extensive analyses of the core effluents were made for water, nonane, alcohol, and mono- and polysulfonates.

An oil bank developed which broke through at 0.08 to 0.1 PV, and 48 to 70% of the oil was recovered in this bank which preceeded breakthrough of monosulfonate and alcohol. Coincidental with the arrival of these components of the slug, the effluent became a milky white macroemulsion which partially separated upon standing. Additional oil was recovered with the macroemulsion. Ultimate recoveries were 90 to 100% of the residual oil. Low apparent interfacial tension was observed between the emulsion and nonane. Alcohol arrived in the effluent at the same time as monosulfonate even though there was extensive adsorption of the sulfonate. Further, alcohol appeared in the effluent well after sulfonate production had ceased, indicating retention of the alcohol in the core. A qualitative model describing the displacement process was inferred from the appearance of the produced fluids and the analyses of the effluents.
The Calculation of Waterflood Recovery From Steady-State Relative Permeability Data
Authors: Richardson J.G.
Published: December 2007

The performance of laboratory water floods is compared with the flooding behavior calculated by the Buckley-Leverett techniques from steady-state relative permeability-saturation relations. Both the steady-state and unsteady-state experiments were conducted on the same sand-packed column. Relative permeabilities were calculated by the Welge technique from the unsteady-state waterflooding displacement experiments and compared with those measured by steady-state techniques. An evaluation of the various calculation procedures was made. It was demonstrated that steady-state relative permeabilities could be used to calculate waterflood performance.

Introduction

To calculate the waterflooding behavior of a given reservoir, relative permeability-saturation relations of the reservoir rack are required. These relative permeabilities are commonly measured on care samples by steady-state experiments such as the Penn State technique. The relative permeabilities obtained in steady-state experiments are calculated from oil and gas flow rates and pressure drops measured under conditions of equilibrium distribution of oil and water in the pore spaces with slow approach to equilibrium. On the other hand, in water floods the water saturation at a given point changes rapidly with time as the flood front passes.

Extensive research has shown that the steady-state relative permeabilities to oil and water are independent of the rate of flow and the fluid viscosities. Research has also demonstrated that the waterflooding performance of homogeneous sands uniformly contacted by water is independent of rate when capillary pressure gradients, which are important in short laboratory columns, are made negligible. However, there is little experimental data in the literature comparing relative permeabilities calculated from steady-state flow experiments with those calculated from flooding experiments.

In this paper, the production data of two water floods and the relative permeabilities calculated from a series of steady-state experiments on an unconsolidated sand column are presented along with the comparisons calculated by the Buckley-Leverett and by the Welge techniques. The purpose of this study was to determine if steady-state relative permeabilities could be used to predict the waterflooding performance. This study also permitted an evaluation of the Buckley-Leverett and Welge calculation procedures and allowed an insight into the nature of microscopic displacement of oil by water.
Influence of Very Low Interfacial Tensions on Relative Permeability
Authors: Bardon Charles , Longeron D. G.
Published: December 2007

Laboratory studies have been conducted to determine the influence of the composition of gas and oil phases on the parameters involved in the description of two-phase flow in porous media when the compositions of the phases vary over a wide range. Relative permeabilities to gas and oil were determined under high pressure and temperature for binary systems (methane/n-heptane, methane/n-decane, etc.), leading to very wide variations of the interfacial tensions values. Investigations were focused specifically on mixtures involving low interfacial tensions, down to 0.001 mN/m.

This study has shown that residual oil saturations and relative permeabilities determined from the displacement tests with a filtration velocity of about 20 cm/hr are affected strongly by interfacial tension, especially when it is lower than 10−2 mN/m.
Future Outlook of Petroleum in the World
Authors: Reistle Carl E.
Published: December 2007

Introduction

The decade since World War II has, in many ways, been one of the most eventful periods of world history. For one thing, the pattern of industrial and political development predicted at the end of World War II is quite different from that which has actually evolved. Many thoughtful people believed that we were close to attaining real world peace and that we would experience the historical pattern of an economic recession following a great war. Of course, neither of these estimates has proved to be correct. The world has suffered several minor wars, that is, minor compared to the World Wars, and certainly there are conditions and forces throughout the world today that constitute a real threat to peace. On the economic side, the forecasters of a major recession have proved to be especially incorrect. There has never been a similar period of time in world history in which economic growth has approach that of these past 10 years.

In the forefront of this phenomenal growth has been a tremendous increase in demand for petroleum products. The purpose of this paper is to attempt to describe this increase in demand, explain how the world oil industry has met the challenge, and speculate a bit about the industry's future.

The Growth in Demand for Petroleum Products

Fig. 1 is a bar-graph on which the consumption of petroleum products by geographic areas for the first year following World War II (1946) is compared with that of 1955. The total world demand has more than doubled in this short period-from 7.8 million B/D (2.84 billion bbl per year) in 1946 to 16.1 million B/D (5.86 billion bbl per year) in 1955. You will notice that, although the United States continues to be the principal market for petroleum products, its rate of increased demand has not been nearly as great as that of other areas, particularly Europe. Another interesting comparison between 1946 and 1955 is the relative demand for the principal products produced from petroleum. Fig. 2 provides a comparison of the world's consumption of gasoline, kerosene, distillate fuel, and residual fuel for 1946 and 1955 in the free world. The greatest increase in demand has been for gasoline and distillate fuels.
The Application of Fractional Flow Theory to Enhanced Oil Recovery
Authors: Pope Gary A.
Published: December 2007

Classical fractional flow theory is generalized, starting with the Buckley-Leverett theory for waterflooding. The mathematics are based on the method of characteristics. The physics and how the problems are treated are analogous to the multicomponent adsorption problem of chromatography; thus, the methods of Helfferich apply. Enhanced oil-recovery (EOR) cases considered are polymer flooding, carbonated waterflooding, hot waterflooding, hydrocarbon miscible flooding, low-tension flooding, and micellar/polymer flooding. The alcohol flooding, enriched gas, and carbon dioxide cases are analogous in many respects to the micellar/polymer case. Finally, three-phase flow problems are treated. Three-phase flow occurs in a variety of EOR processes.
A Statistical Study of Some Waterflood Parameters
Authors: Felsenthal Martin
Published: December 2007

Important parameters needed to forecast waterflood reserves and rates are residual oil saturation (Sor) in the swept zone, relative permeability to injection water (krw), and ratio of peak oil rate to injection rate. To investigate the statistical distribution of these parameters, a review was conducted of laboratory core test results and field performance data.

Residual Oil Saturation in the Swept Zone

Tables 1 and 2 summarize data obtained from relative permeability tests on numerous samples. About 10% of these data came from the literature and the remainder came from unpublished reports for fields in Canada, Libya, the U.K. sector of the North Sea, and fields in the following states: California, Colorado, Illinois, Indiana, Kansas, Mississippi, Montana, Oklahoma, Pennsylvania, Texas, Utah, and Wyoming. Fig. 1 illustrates the distribution of residual oil saturations at the end of laboratory oil/water relative permeability tests. The core test samples were generally small - typically about 7/8-in. (22.3-mm) in diameter. Because of the small sample size, many features of carbonate rock (such as vugs, solution channels, and fractures) were underrepresented or not represented at all. Thus, results shown essentially reflect the intercrystalline porosity. Results indicate that Sor in the swept porosity. Results indicate that Sor in the swept portion of the reservoir is slightly lower in the matrix portion of the reservoir is slightly lower in the matrix of carbonate rocks than in sandstones. A statistical

TABLE 1 - WATERFLOOD RESIDUAL OIL SATURATIONS MEASURED IN CORE TEST SAMPLES

CarbonateSandstone Rock

Mean Average Sor, % pore space 27.7 26.2 Median average Sor, % porespace 26.6 25.2 Number of core samples tested 316 108 Number of source reservoirs 75 20 Standard deviation, % pore space 8.76 8.84

test (t test) showed that the difference is significant at a confidence limit of 90%.Attempts were made to correlate Sor with either KAIR or porosity for each lithology type. These attempts were unsuccessful; that is, the coefficients of correlation were too low to develop significant general correlation equations. Results were as follows:

Coefficients of Correlation (r)Sor vs ln KAIR Sor vs Porosity

Sandstone 0.077 0.073 Carbonate rock 0.209 0.246

Relative Permeability to Water at Residual Oil Saturation

Fig. 2 shows a correlation of krw at Sor with KAIR for a turbidite formation of Repettian (early Pliocene) age from California. The correlation coefficient equaled 0.57, indicating that the correlation shown was significant at a confidence level of 95%.

TABLE 2 - EFFECT OF LITHOLOGY AND KAIR ON THE END POINTS OF OIL/WATER RELATIVE PERMEABILITY CURVES

Permeability group: Low Medium High Permeability group: Low Medium High Range of KAIR, md: (1 to 10) (11 to 100) (101 to 2,000)

Sandstone

Median krw at Sor 0.065 0.133 0.256 Median krw at Sor 0.033 0.095 0.210 Number of coresamples tested 30 213 143

Carbonate Rock

Median krw at Sor 0.211 0.357 0.492 Median krw at Sor 0.179 0.303 0.428 Number of coresamples tested 33 45 24

P. 1303
A New Instrument for Measuring Bulk and Grain Volumes
Authors: Russell William L.
Published: December 2007

A new instrument for measuring bulk and grain volumes is described, and compared in accuracy with two modifications of Nutting's method. All three methods are reasonably fast, and in all three the probable error in the determinations of bulk volume can be kept down to about 0.1 to 0.2 per cent.

Introduction

The new pycnometer described in this paper is designed to give speed without sacrificing accuracy. Some time ago Russell described a somewhat similar apparatus; however, the instrument described in the present paper is more accurate. Nutting designed the pycnometer shown in Fig. 1 (A and B), and Pirson has shown points like those of Fig. 1-D. The procedure described in this paper for using Nutting's pycnometer has been modified from that used by Nutting.

Choice of Liquids

The best liquids for measuring grain volumes are hydrocarbons or chlorinated hydrocarbons which evaporate slowly. Trimethylbenzene or mesitylene, triethylbenzine, carbon tetrachloride, and tertalin have been used for this purpose. Any of these liquids or mercury may be used for measuring bulk volume.

Preventing Errors Due to Invasion of Liquid

Errors due to the invasion of the porous, permeable bulk samples by the liquid of measurement may be prevented or greatly reduced by using mercury, by applying an impervous coating, or by soaking the bulk samples in the liquid of measurement until bubbles cease issuing from them. Errors are produced only by the invasion of the samples which occurs between the movement when the samples are weighed in air and the moment the weight of liquid displayed by the sample in the pycnometers is determined. No error is produced by varying degrees of filling of the pore space of the samples by the liquid of measurement.
Representing Wells in Numerical Reservoir Simulation: Part 1 – Theory
Authors: Williamson Alexander S. , Chappelear John E.
Published: December 2007

A reservoir simulation system uses an analytical model to represent flow within a grid block as it enters or leaves a well. This model is called a well model. We give a description here of the theoretical background of a well model, including how the sandface pressure and saturation boundary conditions can be calculated and how the well boundary itself can be replaced (approximately) by a source function. This paper and the following companion paper, SPE 9770, present a unified viewpoint of material, some of which may be already familiar to simulator developers.
A Simple and Accurate Description of Nonlinear Fluid Leakoff in High-Permeability Fracturing
Authors: Hoek P. J. van den
Published: December 2007

Fluid leakoff in hydraulic fracturing is conventionally described using the well-known linear (Carter) model. Although this works well in low-permeability formations, the linear leakoff assumption may lead to sometimes significant overestimation of fracture dimensions in medium- to high-permeability formations. At present, no methodology is available that allows an easy estimation of the impact of nonlinear fluid leakoff on fracture dimensions and on pressure decline (minifracture) analysis. This paper aims to resolve that deficiency.

An exact numerical solution is presented to the fully transient elliptical fluid-flow equation around a propagating hydraulic fracture for arbitrary pump rate(s). In addition, a simple analytical formula for elliptical leakoff rate is presented that is shown to yield an excellent approximation of the numerical results, both during fracture growth and after shut-in. This formula can be easily incorporated into any existing hydraulic fracture model, and it is applicable over the entire range of fluid leakoff rates (i.e., from low-permeability fracture stimulation on one hand to high-permeability waterflood fracturing on the other).

The above result is applied to a variety of hydraulic fracturing field examples to explore the limits of the linear (Carter) leakoff assumption, both in pressure-decline analysis of minifractures and in fracture design. It is shown that in frac-packing and high-perm cuttings reinjection (CRI), the linear leakoff assumption may lead up to a tenfold overestimation of fracture dimensions.

Conversely, incorporating nonlinear leakoff in the minifracture interpretation of high-permeability fractures will yield larger minifracture radii and lower total leakoff coefficients. This will result in more aggressive pump schedules.
Transport Properties of Porous Media Reconstructed From Thin-Sections
Authors: Hidajat I. , Rastogi A. , Singh M. , Mohanty K. K.
Published: December 2007

The objective of this work is to predict transport properties within any complex porous medium from its 2D microimage. 3D porous media are generated that have the same porosity, autocorrelation, chord length distribution, and lineal path function as a given 2D microimage of a medium. The properties of the reconstructed media are compared with those of the original media. A pore skeleton and Euclidean distance map are determined for the 3D pore-space from which body radius, throat radius, and connectivity distributions are extracted. This network structure is used in calculation of transport properties. Specific surface area is estimated accurately. Permeability and formation factor are estimated approximately. The correlations between adjacent pore bodies and throats are identified.
Horizontal Injectors Rejuvenate Mature Miscible Flood—South Swan Hills Field
Authors: Edwards K.A. , Anderson B. , Reavie B.
Published: December 2007

The South Swan Hills pool, located in northwest Alberta, Canada, is a carbonate reef with an original oil in place (OOIP) of approximately 850 million bbl. Waterflooding began in 1963, and a staged hydrocarbon miscible flood covering most of the field began in 1973. Solvent injection in the main miscible flood was terminated in 1989, and chase gas injection ceased in 1998. In 1994, however, solvent injection was reinitiated into a single pattern in the reef margin area of the field using a horizontal injector and reduced well spacing. The reef margin is an area of thick, stacked pay that experienced high gravity override during the original miscible flood. The horizontal injector was placed at the base of the reef margin to minimize the effects of gravity override and to maximize sweep efficiency. Four patterns have been developed to date. The two earliest patterns have now completed solvent injection and are on chase waterflood. Both patterns are projected to recover almost 1 million bbl of incremental oil per pattern (more than 10% of pattern OOIP) from areas that were part of the original miscible-flood project.

This paper covers the development of the original miscible flood, the redevelopment of the reef margin area using horizontal miscible injectors, and the performance of the four patterns implemented to date. The geological and performance factors that made this redevelopment successful, and their impact on field production, are discussed. Finally, plans for future development of this mature field are presented.
Takula Field: Data Acquisition, Interpretation, and Integration for improved Simulation and Reservoir Management
Authors: King G. R. , David W. , Tokar T. , Pape W. , Newton S. K. , Wadowsky J. , Williams M. A. , Murdoch R. , Humphrey M.
Published: December 2007

This paper discusses the integration of dynamic reservoir data at the flow-unit scale into the reservoir management and reservoir simulation efforts of the Takula field. The Takula field is currently the most prolific oil field in the Republic of Angola.
Quantifying the Economic Impact of 4D Seismic Projects
Authors: Waggoner J. R.
Published: December 2007

Time-lapse 3D, or 4D, seismic imaging has been analyzed by the industry for more than a decade, with a growing number of successful cases being reported in the literature. Two of the most recent 4D case studies1 reporting success are Draugen in the Norwegian North Sea and Gannet-C on the U.K. continental shelf. Both have been technical successes, providing good images of time-lapse changes in the reservoir. These 4D results have changed drilling locations and reduced the risk associated with costly field-development decisions. (Note: from this point forward, "4D" is used to refer to time-lapse seismic imaging.)

The focus of this paper is quantifying the economic impact of 4D. After reviewing some ways that 4D can impact reservoir management, an economic model is developed that can quantify that impact. The decision tree model uses Bayes' theorem to compute the modified probabilities resulting from 4D. The model indicates that, for the case of drilling an infill well, 4D information adds considerable value to the project, even considering that the 4D information is not perfect.
Predicting Reservoir Fluid Phase and Volumetric Behavior From Samples Contaminated With Oil-Based Mud
Authors: Gozalpour F. , Danesh A. , Tehrani D. -H. , Todd A. C. , Tohidi B.
Published: December 2007

The impact of sample contamination with oil-based mud filtrate on phase behavior and properties of different types of reservoir fluids, including gas condensate and volatile oil, has been investigated. Two simple methods are used to determine the uncontaminated fluid composition from contaminated samples. The capability of the methods is demonstrated against highly contaminated samples.

An equation-of-state (EOS)-based method also has been developed to predict the phase and volumetric properties of the retrieved composition. The method determines the required parameters of the EOS for the uncontaminated fluid using the developed phase-behavior models from contaminated-sample data. The method has been examined against experimental data of different types of reservoir fluids with successful results.
Safe Disposal of One Million Barrels of NORM in Louisiana Through Slurry Fracture Injection
Authors: Reed A. C. , Mathews J. L. , Bruno M. S. , Olmstead S. E.
Published: December 2007

During the past 50 years, storage pits and adjacent land around the Bay Marchand facility near Port Fourchon, Louisiana, had accumulated large deposits of nonhazardous drilling and production waste containing naturally occurring radioactive material (NORM). This material primarily included drill cuttings, drilling mud, produced sand, salt water, pipe scale, crude oil, and precipitates. To remediate this site, the operator chose to reinject the material into the deep subsurface through on-site slurry fracture injection (SFI). This process provided greater environmental security compared to alternative surface pit or landfill disposal and at a much lower cost than off-site transport and disposal options.

More than 1 million barrels of pit soil and canal bottoms were safely disposed into a single well during 2 years of injection that concluded in March 2000. Solid waste was mixed with water to create a slurry and injected downhole at greater than the formation parting pressure into a weakly consolidated sandstone formation at depths from 4,400 to 5,000 ft. Injection operations were episodic, generally taking place for 11 hours per day, 5 days per week. This allowed the formation pressure to decline each day to the initial reservoir pressure. The project was designed and extensively monitored to maintain and verify containment within the permitted interval. Downhole pressure was continuously monitored, allowing analysis of daily falloff pressure. Waste containment was confirmed through a combination of shut-in pressure analysis and periodic step-rate tests, gamma logs, and temperature surveys.

In addition to the improved environmental protection provided by this technology, the on-site operation was a fraction of the off-site disposal costs. This paper describes the project design and permitting, injection operations, containment monitoring and analysis, and project economics.
Pressure-While-Drilling Measurements To Solve Extended-Reach Drilling Problems on Alaska's North Slope
Authors: Mallary C. R. , Varco Martin , Quinn D'Arcy
Published: December 2007

Extended-reach drilling (ERD) is playing an important role in the economic development of Alaska's North Slope oil reserves. For some ERD wells, careful well planning and existing drilling practices are sufficient to avoid problems, such as wellbore instability, lost circulation, and stuck pipe. However, recent Alaskan experience has shown that as well step-outs increase, some operational practices developed on conventional wells are inadequate to successfully deliver cost-effective ERD wells. On these wells, careful planning alone cannot always prevent costly drilling problems.

The ability to analyze downhole annular pressures with pressure-while-drilling (PWD) data has proven invaluable to the drilling engineer. The value of this information is not fully realized, however, until it is put in the hands of the rig operator, who can act on it in real time. This paper examines the impact PWD measurements have made in recent Alaska ERD wells and focuses on both planning and operational uses. Field data are presented from problem and nonproblem wells to underscore successful and unsuccessful operational practices. The importance of rig-site training in equivalent-circulating-density (ECD) management and the linkage to drilling, circulating, and tripping practices are developed.
Effect of Depletion Rate on Gas Mobility and Solution Gas Drive in Heavy Oil
Authors: Kumar R. , Pooladi-Darvish M. , Okazawa T.
Published: December 2007

Some heavy oil reservoirs in western Canada and Venezuela show anomalously high primary recovery under solution gas drive process. The pressure decline rate in these reservoirs is low compared to that expected under solution gas drive in conventional oil reservoirs. There is now increasing evidence that gas mobility is extremely low in these reservoirs.

The objective of this study is to conduct solution gas drive experiments in a sandpack saturated with a heavy oil and examine the effect of depletion rate. Depletion rate was varied by more than two orders of magnitude. The results showed that gas mobility was a function of depletion rate and decreased with increasing depletion rate. Other notable observations were that supersaturation increased with depletion rate and that critical gas saturation was 3 to 4%, slightly increasing with increasing depletion rate.

Interpretation of the results confirmed that gas mobility is quite low. Representation of the low mobilities using relative permeability required low values of the order of 10−5–10−4, which decreased with increasing depletion rate.
Differential Scanning Calorimetry: A New Technique To Characterize Hydrate Formation in Drilling Muds
Authors: Dalmazzone Didier , Dalmazzone Christine , Herzhaft Benjamin
Published: December 2007

With the increasing number of deep offshore drilling operations, operators and service companies are confronted by technical challenges ever growing in complexity. Extreme conditions encountered at these depths require an adaptation of the drilling muds. In particular, the range of temperatures and pressures encountered (as low as ‒1°C and up to 400 bar) is favorable for the formation of gas hydrates. Gas hydrates are solid structures formed from water and gas; water contained in drilling muds under certain temperature and pressure conditions will form solid cages that entrap the gas molecules. Formation of these solid gas hydrates is liable to plug kill and chokelines as well as the annular and may cause interruption of the drilling operation and even destruction of rig equipment. Deep offshore drilling operators are aware of this problem, and some operational solutions and drilling mud formulations have been proposed and utilized, but when extreme water depths are attained, classical inhibitor solutions alone may be ineffective. The usual way to determine the thermodynamic conditions of the formation of gas hydrates in drilling mud formulations is to use a pressure/volume/temperature (PVT) cell. This technique requires heavy instrumentation and often does not permit work with a whole formulation (especially in the presence of solids). Moreover, PVT cells do not give a quantitative evaluation of the kinetic properties of gas hydrate formation.

In this work, we present experiments using differential scanning calorimetry (DSC) to determine the thermodynamic equilibrium properties of methane hydrate in calcium chloride solutions. Additionally, thermograms of an emulsion and a complete drilling mud are presented that show the possibility of characterizing hydrate thermodynamics in complex systems as synthetic mud formulations. This technique is easy to use, and, when correctly interpreted, it enables the dangerous zones for hydrate formation to be determined.
Streamline Tracing on Curvilinear Structured and Unstructured Grids
Authors: Prévost Mathieu , Edwards Michael G. , Blunt Martin J.
Published: December 2007

The streamline method has proven to be extremely successful for reservoir simulation.1 For a Cartesian grid, the standard five-point (seven-point in 3D) discrete pressure equation is employed within the IMPES streamline method. The accuracy of the velocity field plays a critical role in the success of the technique, which relies on precise determination of streamline paths.

Modeling complex geology and geometry requires the use of sophisticated grids, and thus the ultimate power of the streamline method will only be realized when the method is extended to general curvilinear grids.

In this paper, a generalization of the Cartesian tracing algorithm is developed for general tensor fields on structured (corner-point) grids and unstructured grids. The extension of the method requires the identification of appropriate volumes and fluxes over which tracing equivalent to the Pollock Cartesian method2 can be performed. Essential components of the method include the use of flux-continuous finite-volume schemes for the different grid types coupled with a novel flux recovery technique and a generalization of streamline tracing to polygons.
E&P Waste Management in the Orinoco Delta
Authors: Melchor A. E. , Costa A. da , Rodriguez C. , Peña J. R.
Published: December 2007

Tropical wetlands and the presence of indigenous people with an ancient culture and a strong economic dependence on natural resources made the Pedernales field an environmental and socially sensitive location. BP's challenge was to work in this area without disrupting the lives of nearby settlements while preserving the environment.

The Pedernales field was designed as a zero-discharge operation in which the main waste streams were to be reinjected. However, the initial waste-management strategy had to be changed because of operational constraints to one that also allowed waste disposal in an environmentally sound way. Waste recycling, biotreatment, and temporary offsite treatment and disposal were key processes in the new waste-management strategy.

During 5 years of operation, a total of approximately 41.5×104 m3 of exploration and production (E&P) waste were handled and disposed of successfully. Poor area drainage combined with high annual rainfall and low natural soil-supporting capacity required using unconventional tools and equipment. This was especially needed for disposing of drill cuttings.

Drill cuttings were handled by turning them into slurry with a specially designed mixer, then pumping the slurry to a distance of up to 2 km from the storage barge. The cuttings originally contained up to 6% oil and grease but degraded to 1% within approximately 180 days. This is considered a short time with the high level of soil/waste moisture saturation taken into account. Continuously monitoring water and soil with a simple on-site laboratory proved to be adequate and cost-effective for process control and for preventing pollution.
Application of Low-Dosage Hydrate Inhibitors in Deepwater Operations
Authors: Fu B. , Neff S. , Mathur A. , Bakeev K.
Published: December 2007

Novel low-dosage hydrate inhibitors (LDHI) have been developed for applications in oil and gas fields. A new generation of kinetic inhibitors has been used to prevent hydrate formation frequently encountered in deepwater operations. These chemicals effectively inhibit hydrate formation, regardless of the water cut in the system. They also exhibit a low toxicity that leads to very favorable environmental ratings. Valuable experience has been learned from recent laboratory studies and field trials with respect to the application limits and implementation techniques for these new products. The key to the overall success is a full integration of a good front-end design, a comprehensive deployment plan, and an effective monitoring program. An overview of the chemistry of these new inhibitors is discussed briefly along with their performance under simulated deepwater conditions. In addition, the effect of LDHI on hydrate formation and the effect of pressure on LDHI performance are addressed.
Kinetics of Silica Deposition From Simulated Geothermal Brines
Authors: Bohlmann E. G. , Mesmer R. E. , Berlinski P.
Published: December 2007

In our experiments, supersaturated brines were passed through columns packed with several forms of silica (crystalline α-quartz, polycrystalline α-quartz, and porous Vycor). Also, silica deposition on ThO2 microspheres and titanium powder was studied under controlled conditions of supersaturation, pH, temperature, and salinity. The residence time was varied by adjustments of flow rate and column length. The silica contents of the input and effluent solutions were determined colorimetrically by a molybdate method that does not include polymers without special pretreatment.

The following observations have been made.

Essentially identical deposition behavior was observed once the substrate was coated thoroughly with amorphous silica and the Brunauer-Emmett-Teller (BET) surface area of the coated particles was taken into account. The reaction rate is not diffusion-limited in the columns. The silica deposition is a function of the monomeric [Si(OH)4] concentration in the brine. The deposition on all surfaces examined was nucleated spontaneously. The dependence on the supersaturation concentration, hydroxide ion concentration, surface area, temperature, and salinity were examined. Fluoride was shown to have no effect at pH 5.94 and low salinity.

A cursory study of the effect of salinity showed little difference for 0.09 and 1.0 molal NaCl solutions; however, increasing the concentration to 4.0 molal increased the deposition rate by more than one order of magnitude. The empirical rate equation that describes our data in 1 molal NaCl in the pH range 5 to 8 and temperatures from 60 to 120°C is

(1) − d [ Si ( OH ) 4 ] d t = 0.12 A { [ Si ( OH ) 4 ] − [ Si ( OH ) 4 ] e } 2 [ OH − ] 0.7 ,

where A is the amorphous SiO2 surface area in square centimeters per kilogram of water in column voids; t is minutes; and the concentrations are in molal units. Hydroxide concentration was derived from the measured pH and the ionization quotient for water. In the expression given above, the rate constant is essentially independent of temperature over the range 60 to 120°C.
Radial Steam Flow in Two-Phase Geothermal Reservoirs – Comparison of Analytical and Finite Difference Solutions
Authors: Moench Allen F.
Published: December 2007

A linear closed-form analytical solution for the radial flow of steam toward a producing well in a vapor-dominated geothermal reservoir is compared with a finite difference solution to the nonlinear equations of fluid flow and energy change. Assumptions used in the development of the equations are that (1) the liquid phase, initially uniformly distributed within the reservoir, is immobile, (2) the relative permeability to steam is constant, (3) local thermal equilibrium exists within the reservoir, (4) temperature changes are due only to phase change, and (5) effects of vapor-pressure lowering are negligible. With the onset of production, vigorous vaporization of liquid water in the reservoir near the wellbore creates a dry region that increases in volume as production continues. This behavior produces a circular moving boundary that separates superheated steam in the dry zone from saturated steam in the wet zone. The rate of movement of this boundary, the pressure drawdown, and the temperature and saturation distributions are obtained analytically by applying the solution to the linearized equations of flow in radial coordinates. Results obtained numerically using a finite difference solution to the nonlinear equations of fluid flow and energy agree closely with the analytical approach in spite of the nonlinearities involved.
Selective Absorption of H2S From Sour Gas
Authors: Hohlfeld R.W.
Published: December 2007

Selective absorption of H2S from sour gas with caustic by gas/liquid scrubbing is a new approach for oilfield operations to meet environmental and safety restrictions. This technology demonstrates that by maintaining a very short contact time in a gas/liquid scrubber it is possible for caustic to react with and remove H2S from a sour gas.

Introduction

Hydrogen sulfide (H2S) and carbon dioxide (CO2) are natural contaminants of gases from well casings, combustion floods, geothermal steam, or process streams. Because of safety, environmental or corrosion considerations, it normally is desirable to remove the H2S from such gases. However, these factors do not dictate the removal of CO2, and it is not desirable because of the cost involved. Safety standards set by the U.S. Occupational Safety and Health Admin. limit worker exposure to H2S at 10 ppm for an 8-hour day. Environmental guidelines ppm for an 8-hour day. Environmental guidelines require limited sulfur emissions, particularly of H2S, which has a characteristic "rotten egg" odor at levels of 3 ppm. Corrosivity of wet H2S gases is well known because of its acidic character.

Many commercial methods exist to remove H2S from sour gas streams, though they all have their limitations. Some processes may be limited by the volume of gas they can handle or by the level of H2S or CO2 in the gas stream. Others may prove to be costly because of the capital investment or operating expense. Still others are not suitable for the field because of the complexity of operation, requiring highly trained personnel.

In the H2S removal system described in this paper, these objections largely are overcome, as evidenced by a number of production units based on this technology. Experience has shown that this system (1) has a very low capital investment cost (2) has a simple design based on gas/liquid scrubbing (3) has straightforward installation and operation (4) will remove H2S efficiently, and (5) can treat gases widely varied in composition and volume. These units have proved effective in H2S removal from operations as widely divergent as pipeline-quality gas plants to remote locations treating vent gases with plants to remote locations treating vent gases with 10% H2S.

Theory

The principle of the technology presented here is based on a patent issued to The Dow Chemical Co. It states (and is reduced to practice in the method discussed here) that H2S can be absorbed selectively from sour gases also containing CO2 by maintaining a proper residence contact time between the gas and an alkaline liquid. Normally, in a typical wet scrubbing operation both acidic gases (H2S and CO2) would be absorbed. However, the absorption and reaction of H2S in a strongly alkaline solution (caustic soda) is virtually instantaneous while the absorption of CO2 is a much slower reaction. Thus, if the gas is allowed to contact the liquid for a controlled short time, the CO2 absorption and reaction with caustic will be insignificant. Because H2S does not have this limitation, it is absorbed preferentially. preferentially. JPT

P. 1083
Potential Application of Amine Methylene Phosphonate-Based Inhibitor Species in HP/HT Environments for Improved Carbonate Scale Inhibitor Performance
Authors: Graham G. M. , Dyer S. J. , Shone P.
Published: December 2007

In recent years, a number of new high-pressure/high-temperature (HP/HT) reservoirs have been developed in the North Sea [for example, the Eastern Trough Area Project (ETAP) and Shearwater fields] that have several important scale-control issues. In addition to their ability to prevent scale formation, these include inhibitor/ brine compatibility and the thermal stability of the scale inhibitor. Previous works have strongly indicated that amine methylene phosphonic acid-based inhibitor species, such as pentaphosphonate (DETPMP) and hexaphosphonate (TETHMP), are considerably less thermally stable than polymeric species, such as PVS and the S-Co species. As a consequence, the phosphonate-based species have been reported as less applicable for deployment in high-temperature reservoir systems. However, more recent studies that examined a range of different amine methylene phosphonic acid-based inhibitor species have shown that certain species are thermally stable at temperatures exceeding 160°C. This paper presents the initial screening study undertaken to select a scale inhibitor for the Shearwater reservoir and includes an examination of some phosphonate species to determine potential application in HP/HT reservoir systems.
Asphaltene Characterization and Mitigation in South Kuwait's Marrat Reservoir
Authors: Kabir C. S. , Jamaluddin A. K. M.
Published: December 2007

This study addresses two aspects for mitigating production problems in south Kuwait's Marrat wells in the Magwa area of the Greater Burgan field.

Characterizing single-phase oil samples collected from four wells. Finding a pragmatic and cost-effective solution to tubular-deposition problems.

We took two approaches for laboratory investigation. In the first approach, a gravimetric technique was used to establish asphaltene onset pressures (pao) at various temperatures, leading to the generation of the asphaltene flocculation envelope (AFE). The second approach entailed the use of acoustic resonance technique (ART) for rapid determination of both pao and bubblepoint pressure (pb) in one experimental run en route to the development of a solvent— deasphalted oil.

Fluid characterization also included thermodynamic modeling. Asphaltene is treated here as a solid phase in equilibrium with the reservoir fluid, which is modeled by an equation-of-state (EOS) model. We reproduced the observed features of various isotherms quite well, lending credence to the modeling approach.

Following fluid characterization, we sought a cost-effective and environmentally friendly solvent. The search for a solvent led us to the development of deasphalted oil. We designed and conducted a series of experiments to deasphalt the Marrat oil and examine its potency as a solvent. Results showed that the use of 20% deasphalted oil with 1% dispersant, both by volume, can ensure solubility of asphaltenes in the entire flow string during production. EOS modeling on deasphalted oil was also done for computing onset pressures at various temperatures with good success. Field trial results are also included to show its partial success in well-bore remediation.
The Accuracy of PVT Parameters Calculated From Computer Flash Separation at Pressures Less Than 1,000 psia
Authors: Glaso O.S. , Whitson C.H.
Published: December 2007

Introduction

Standing derived a set of equations that fit the equilibrium constant data of Katz and Hachmuth at pressures less than 1,000 psia (6.895 MPa) and pressures less than 1,000 psia (6.895 MPa) and temperatures below 250 degrees F (121 degrees C). A standard deviation (SD) of 3.5% between calculated and chart K values is reported by Standing. Not reported, however, is the accuracy of the Katz and Hachmuth K values applied to reservoir fluids of various paraffinicities and containing significant amounts of nonhydrocarbons. Because the data of Katz and Hachmuth were for an Oklahoma City crude oil containing no nonhydrocarbons, it was necessary to investigate their general applicability. A separator flash program was developed that incorporates the Standing K-value equations. The program was used to analyze 15 crude oils from various regions of the world, some containing substantial amounts of nonhydrocarbons. Flash parameters were calculated and compared with experimental values obtained from a PVT analysis of the fluid samples. GOR, average gas PVT analysis of the fluid samples. GOR, average gas gravity, stock-tank oil gravity, and bubble-point formation volume factor were used in the comparisons.

Flash Program Description

Our vapor and liquid equilibrium calculations involved use of the Katz and Hachmuth K values fitted by Standing. The algorithm used for calculations is described by Standing. The basic equation for fitting K-value data given by Hoffman et al. was used in this study:

.......................(1)

where coefficients a and c are functions of separator pressure. Psp is measured in psia, and F is a pressure. Psp is measured in psia, and F is a characterization factor. Equations for constants a and c appear in Ref. 1. The characterization factor, F, as defined by Hoffman et al., is

........................(2)

where separator temperature, Tsp, is in R, Tb is the average boiling-point temperature in R, and coefficient b is defined for the pure components C3, iC4, nC4, iC5, nC5, and C6 as

........................(3)

All other fractions except C7+ (i.e., C1, C2, CO2, N2, and H2S) have modified values of b and Tb, and these values can be determined by the procedure outlined in Ref. 1. The K value for the C7+ fraction was determined by the equation

.............................(4)

where KC7 was calculated as a pure component. Ref. 1 provides an alternative method to determine KC7+. This provides an alternative method to determine KC7+. This method was not available to the authors at the time this study was conducted. We recommend that the procedure given in Ref. 1 be used to determine KC7+. A check was made to see what, if any, error resulted from using Eq. 4. It was found that there is no significant loss of accuracy in calculated flash parameters unless the oil contains a large C7+ fraction (greater than 0.70).

JPT

p. 1811
An Experimental Study for Mechanical Formation Damage
Authors: Soares A. C. , Ferreira F. H. , Vargas E. A.
Published: December 2007

This work presents triaxial experiments that were carried out in different stress paths, with measurements of P- and S-wave acoustic velocity and permeability, to evaluate mechanical formation damage. In some reservoirs, large deformations occur during oil production because of the effective stress increase. This may cause permanent damage to the reservoir as the rock structure changes, lowering the permeability and the final oil recovery. The experiments showed that plastic behavior is always present and that a "cap" model may represent the yield region. This methodology allowed a near-wellbore evaluation and permeability investigations using a stress-path concept.
Some Rock-Mechanical Aspects of Oil and Gas Well Completions
Authors: Geertsma J.
Published: December 2007

Elementary borehole- and perforation-stability problems in friable clastic formations for unrestricted fluid flow between reservoir rock and underground opening are treated on the basis of linear poroelastic theory. Thermal stress effects caused by a temperature difference between reservoir and borehole fluids can be predicted from the mathematical similarity of poro- and thermoelasticity. A tension-failure condition applies for the prediction of hydraulic fracture initiation in a formation around injection wells. The resulting equations are partially well-known.

Similarly, a uniaxial compression-failure condition should predict perforation failure leading to sand influx in production wells. The major difference between these situations is that, at sufficient depth of burial, the tensile strength of a friable rock mass has only a minor effect on the fracturing pressure level, but the actual value of the compressive strength plays a crucial role in the prediction of sand-influx conditions. Practical suggestions for resolving the latter are given.