bluuebunny/crossref_metadata_2025 huggingface dataset:
Effects of Impurities on Minimum Miscibility Pressures and Minimum Enrichment Levels for CO2 and Rich-Gas Displacements
Authors: Metcalfe R. S.
Published: December 2007

Multicontact miscible displacement processes are becoming increasingly popular as a means of recovering secondary and tertiary oil reserves in the U.S. and Canada. Economics of multicontact miscible flooding are governed to some extent by the availability of large sources of high purity CO2 or suitable liquefied petroleum gas (LPG) streams. This is because achievement of miscibility depends on the solvent composition as well as the system temperature and pressure. Atypical components in a CO2 or solvent stream therefore may increase the required pressure or enrichment levels for achievement of miscibility.

Several papers have been published discussing the pressure (for CO2) and composition (for rich gas) levels required for miscible displacement. The potential CO2 supply could be increased if complicated cleanup procedures for injected and produced fluids were not required. For engineering studies it is important that CO2 streams containing H2S and hydrocarbons be evaluated for their miscible flooding potential. It is also important to evaluate the effects of CO2 and C5 + components in rich gas mixtures to determine whether they can be used to reduce calculated enrichment levels for solvent systems.

This paper presents results of studies using mixtures of CO2, H2S, and C1, CO2-LPG, and rich gas solvents containing CO2 or C5 to displace oil miscibly in slim-tube experiments. The purpose of this work is to show the effects of various components on pressure and compositions required for miscibility. As expected, the changes in CO2 miscibility pressure are direct functions of temperature. It is reported that the addition of H2S and C2+ hydrocarbons lowers the miscibility pressure for CO2, whereas the presence of C1 in a CO2 solvent increases it. More important, the results give a quantitative titative measure of the degree of reduction/elevation in miscibility pressure to be expected with impure CO2 streams. The paper also presents similar results from displacements with typical rich gas solvents mixed with CO2 and/or C5. It is reported that CO2 increases the minimum enrichment required, while a heavier hydrocarbon component actually can reduce anticipated enrichment levels.
Computation of Multiphase Equilibrium For Compositional Simulation
Authors: Mehra Rakesh K. , Heidemann Robert A. , Aziz Khalid
Published: December 2007

A numerical scheme has been developed for calculation of multiphase equilibria. The scheme is applied to a thermodynamic model that employs a modified version of the Peng-Robinson equation for all phases except possibly an aqueous phase. Henry's constants are used for computation of solute fugacities in the water phase. The numerical scheme makes "optimal" use of first-and second-order iterative schemes and circumvents the problems reported by previous investigators. An outline of the scheme is presented with references to other sources where complete details are available. Examples of two-, three-, and four-phase separations are presented to demonstrate the range of the proposed scheme. Limited comparison with experimental data also is provided. The scheme may be embedded in compositional reservoir simulators for the modeling of oil recovery by such processes as hydrocarbon gas injection, nitrogen injection, and CO2 floods.
The Contribution of Logging Data to Sedimentology and Stratigraphy
Authors: Serra O. , Abbott H. T.
Published: December 2007

Until recently, the lithology and sedimentology of formations penetrated by a well could be studied only through the analysis of cores. Now a technique has been developed using multivariate analysis of logging data to give a high-resolution sedimentological description of any sequence of formations.

The number of different logs and their range allow determination of many of the physical characteristics of the rock.

The definition of a lithofacies has been extended by introducing the concept of an electrofacies, constructed on the basis of all the logging data at any depth interval. Thus, each logging datum is considered a descriptor for purposes of establishing electrofacies in a logged interval. Once established, electrofacies then can be correlated with actual geologic facies, if the logged interval has been cored.
Ion Exchange With Clays in the Presence of Surfactant
Authors: Hirasaki George J.
Published: December 2007

The transport of sodium and calcium through porous media in the presence of clays and surfactant has been calculated. The exchange of the cations with both the clays and the surfactant micelles is assumed to result entirely from electrostatic association. The results show that a system in which the preflood, slug, and drive have the same sodium and calcium concentration can have a significant increase in the calcium concentration in the surfactant bank and a significant decrease in calcium concentration in the drive because of ion exchange. A process with a salinity gradient design can have a decrease in calcium concentration in the surfactant bank compared with the injected slug because of ion exchange.
Evaluation of the Interfacial Tension Between a Microemulsion and the Excess Dispersed Phase
Authors: Ruckenstein E.
Published: December 2007

From a consideration of the thermodynamic stability of microemulsions, one can establish a relation between the interfacial tension y at the surface of the globules and the derivative, with respect to their radius re, of the entropy of dispersion of the globules in the continuous medium. Expressions for the entropy of dispersion are used to show that γ is approximately proportional to kT/re2, where k is Boltzmann's constant and T is the absolute temperature. Since the environment of the interface between the microemulsion and the excess dispersed medium is expected to be similar to that at the surface of the globules, these expressions are used to evaluate the interfacial tension between microemulsion and excess dispersed medium. Values between 10−1 and 10−3 dyne/cm that decrease with increasing radii are obtained, in agreement with the range found experimentally by various authors. The origin of the very small interfacial tensions rests ultimately in the adsorption of surfactant and cosurfactant on the interface between phases. The effect on the interfacial tension of fluctuations from one type of microemulsion to the other, which may occur near the phase inversion point, is discussed.
Applications for Polycrystalline Diamond Compact Bits From Analysis of Carbide Insert and Steel Tooth Bit Performance
Authors: Madigan J.A. , Caldwell R.H.
Published: December 2007

A thousand field runs of typical roller cone and diamond drill bits were studied to form a comparative basis for assessing the impact of the polycrystalline diamond compact bit. Statistical analysis of mud log data was conducted on a formation-by-formation basis involving 2,581 data intervals. Baseline performance in general drilling was established, and key drilling situations for improved performance with the new bits were determined.

Introduction

During 1979, a study was conducted to document performance of specific commercially available drill bits in more than 1,000 actual field runs to form a comparative basis for assessing the impact of a new innovation - the polycrystalline diamond compact bit. Three basins were studied - the Williston and Permian basins in the U.S. and the North Sea basin. Sedimentary environments ranged from easily drilled, soft sediments to dense, extremely hard and abrasive rock, with an associated range of drilling practices and problems. Statistical analysis of data derived from mud logs was conducted on a formation-by-formation basis, involving 2,581 data intervals. The resulting information is a computerized bit performance data base detailing rate of penetration, footage, rotary hours, and key drilling parameters including mud properties, weight on bit, rotary speed, and rock type.

In addition to forming a baseline to evaluate performance of new bit designs, the study highlights key problem drilling situations where polycrystalline diamond compact bits can provide improved performance - e.g., overbalanced drilling, deviation control, high-rpm drilling, slim-hole drilling, and other applications. Actual testing of polycrystalline diamond compact bits in these applications has been in progress both in the U.S. and Europe, with favorable results to the baseline data. The paper outlines the study and offset comparisons of polycrystalline diamond compact bits with conventional bits in slim-hole drilling, oil-base fluids, pressure coring, and offshore drilling.

Early Development Efforts on Polycrystalline Diamond Compact Drag Bits

The U.S., consuming some 40% of the free world's oil production while producing only 19%, is faced with the challenge of rapidly boosting production to avoid increasing dependence on expensive foreign oil and the resulting consequences to the economy. This must result in more drilling. Drilling costs have increased at almost exponential rates, and the industry continually is looking to new technology to halt this trend. This new technology includes advances in drill bit design directed toward improving both overall performance and performance of specific designs in particular problem drilling situations.
Effect of Non-Darcy Flow on the Constant-Pressure Production of Fractured Wells
Authors: Guppy K. H. , Cinco-Ley Heber , Ramey Henry J.
Published: December 2007

In many low-permeability gas reservoirs, producing a well at constant rate is very difficult or, in many cases, impossible. Constant-pressure production is much easier to attain and more realistic in practice. This is seen when production occurs into a constant-pressure separator or during the reservoir depletion phase, when the rate-decline period occurs. Geothermal reservoirs, which produce fluids that drive backpressure turbines, and open-well production both incorporate the constant-pressure behavior.

For finite-conductivity vertically fractured systems, solutions for the constant-pressure case have been presented in the literature. In many high-flow-rate wells, however, these solutions may not be useful since high velocities are attained in the fracture, which results in non-Darcy effects within the fracture.

In this study, the effects of non-Darcy flow within the fracture are investigated. Unlike the constant-rate case, it was found that the fracture conductivity does not have a constant apparent conductivity but rather an apparent conductivity that varies with time. Semianalytical solutions as well as graphical solutions in the form of type curves are presented to illustrate this effect.

An example is presented for analyzing rate data by using both solutions for Darcy and non-Darcy flow within the fracture. This example relies on good reservoir permeability from prefracture data to predict the non-Darcy effect accurately.
Vesicular Dispersion Delivery Systems and Surfactant Waterflooding
Authors: Puig Jorge E. , Franses Elias I. , Talmon Yeshayahu , Davis H. Ted , Miller Wilmer G. , Scriven L. E.
Published: December 2007

Surfactant waterflooding processes that rely on ultralow interfacial tensions suffer from surfactant retention by reservoir rock and from the need to avoid injectivity problems. New findings reported here open the possibility that by delivering the surfactant in vesicle form, more successful low-concentration, alcohol-free surfactant waterflooding processes can be designed.

Basic studies of low concentration (⩽2 wt%) aqueous dispersions of lamellar liquid crystals of a model surfactant, Texas No. 1, have established the role of dispersed liquid crystallites in the achievement of ultralow tensions between oil and water. Recent work, including fast-freeze, cold-stage transmission electron microscopy (TEM), reveals that sonication both in the absence and the presence of sodium chloride converts particulate dispersions of Texas No. 1 into dispersions of vesicles, which are spheroidal bilayers or multilayers less than 0.1 µm in diameter filled with aqueous phase. Vesicles ordinarily revert only very slowly to the bulk liquid crystalline state. We find, however, that their stability depends on their preparation and salinity history, and that contact with oil can accelerate greatly the reversion of a vesiculated dispersion and enable it to produce low tensions between oil and water.

Tests with Berea cores show that surfactant retention and attendant pressure buildup can be reduced greatly by sonicating Texas No. 1 dispersions to convert liquid crystallites to vesicles. In simple core-flooding experiments both the unsonicated liquid crystalline dispersions and the sonicated vesicle dispersions are able to produce substantial amounts of residual oil. We point out implications and directions for further investigation.
Polymer/Surfactant Transport in Micellar Flooding
Authors: Chiou C. S. , Kellerhals G. E.
Published: December 2007

For the surfactant formulations used (particular surfactant concentration, surfactant type, cosolvent type, cosolvent concentration, etc.), the results show that surfactant systems containing polymer as a mobility control agent may exhibit adverse polymer transport behavior during flow through porous media. Polymer generally lagged behind the surfactant even though the two species were injected simultaneously in the surfactant slug. This poor polymer transport definitely could have a detrimental effect on the efficiency of a micellar flooding process in the field. Phase studies show that when some surfactant systems containing xanthan gum are mixed with crude oil at various salinities, a polymer-rich, gel-like phase forms. The polymer lag phenomenon in core tests can be related to phase separation due to divalent cations generated in situ as a result of ion exchange with the clays and the surfactant.
Controlling Numerical Dispersion by Variably Timed Flux Updating in Two Dimensions
Authors: Larson R. G.
Published: December 2007

The variably-timed flux updating (VTU) finite-difference technique is extended to two dimensions. VTU simulations of miscible floods on a repeated five-spot pattern are compared with exact solutions and with solutions obtained by front tracking. It is found that for neutral and favorable mobility ratios, VTU gives accurate results even on a coarse mesh and reduces numerical dispersion by a factor of 10 or more over the level generated by conventional single-point (SP) upstream weighting. For highly unfavorable mobility ratios, VTU reduces numerical dispersion, but on a coarse mesh the simulation is nevertheless inaccurate because of the inherent inadequacy of the finite-difference estimation of the flow field.
Evaluation of Acid-Gelling Agents for Use in Well Stimulation
Authors: Crowe C. W. , Martin R. C. , Michaelis A. M.
Published: December 2007

Various polymers and other thickening agents have been evaluated as gelling agents for hydrochloric acid (HCl). These materials were compared on the basis of thickening efficiency, acid stability, and residue formation upon spending of the acid. Thickeners tested include xanthan polymers (XP), guar gum (GG), hydroxyethyl cellulose (HEC), carboxymethylhydroxyethyl cellulose (CMHEC), polyacrylamide (PAM), polyvinyl alcohol (PVA), polyvinylpyrrolidone (PVP), acrylamide/sodium-2-acryl-amido-2-methylpropane sulfonate copolymer (PAM/AMPS), and a cationic surfactant that thickens acid when used at high concentrations.

Of the thickening agents tested, XP showed the greatest overall potential for use as an acid gelling agent. This polymer is an efficient viscosity builder and has good stability in 15% HCl at temperatures up to 150°F. Computer model studies, which take into consideration cool-down and gel degradation rate at various stages of acid spending, indicate viscosity is maintained when treating wells that have bottomhole temperatures (BHT's) up to 220°F. Since the gelled acid retains its viscosity during spending, both reaction rate and fluid leakoff are retarded. Laboratory studies simulating downhole spending conditions yield a 3.6-fold increase in spending time for gelled 15% HCl (22-cp) compared with ungelled acid. Well test results are presented that demonstrate the effectiveness of acid fracturing treatments using HCl with XP.
Sulfur Plant Operations in Jay and Flomaton Fields
Authors: Henderson J.K. , Hudson C.W. , Kimble E.L.
Published: December 2007

Jay field sour-oil and Flomaton field sour-condensate production facilities are owned jointly and operated by Exxon in the northwest-Florida/south-Alabama area. They have provided extensive experience with sulfur plant operations and maintenance. Experience with different sulfur plant designs is discussed along with sulfur catalyst problems such as coking, sulfur condensation, thermal degradation, and sulfaction. Sulfur plant maintenance, surveillance, and safety also are addressed.

Introduction

The Jay field, discovered in 1970 and unitized in 1974, is in Florida's northwest panhandle.1 This sour-oil field producing from the dolomitized Smackover carbonate is producing 109,500 BOPD (corresponding to the permitted fieldwide SO2 emissions) with associated sweet-gas volumes of 140 MMcf/D. The full wellstream off-gas contains 10% H2S and 3% CO2. Nine separate crude-stabilization, sour-gas-treating, and sulfur-recovery plants have been designed and built to achieve a minimum 96% sulfur recovery as required by the State of Florida. The Flomaton sour-gas condensate field, 10 miles northwest of the Jay field in southern Alabama, produces from the Norphlet sandstone formation. This nonunitized field was discovered in 1968 and produces 2,600 B/D of stabilized condensate and 15 MMcf/D of sweet gas. The full wellstream gas contains 10% H2S and 40% CO2, for which the State of Alabama requires a sulfur recovery of 91%.

Operation of the Jay field treating facilities has provided experience in straight-through sulfur plants with various reheat designs such as acid-gas reheat burners, indirect reheat using steam, and hot-gas bypass reheat. The Flomaton sulfur plant uses a split-flow design because of the high CO2 content of its acid gas.

This paper reviews these sulfur plant operations including initial operating problems and solutions; sulfur plant maintenance procedures such as the annual plant turnaround activities, refractory repairs, and sulfur-boiler inspections; and daily operational surveillance and sulfur recovery testing for regulatory compliance. Sulfur plant safety procedures, emergency shutdowns, and operator-training programs for processing of toxic H2S gas also are described.
Flow Increase in the Trans Alaska Pipeline Through Use of a Polymeric Drag-Reducing Additive
Authors: Burger E.D. , Munk W.R. , Wahl H.A.
Published: December 2007

The first commercial use of a polymeric drag-reducing additive to increase the flow rate in a crude oil pipeline began during 1979 in the Trans Alaska Pipeline System (TAPS). This paper discusses the details of the two drag-reduction experiments conducted in TAPS that ultimately led to the decision for full-scale additive use. The logistics pertaining to and the benefits resulting from the current application also are discussed.

Introduction

Drag reduction is a well-known phenomenon first observed in the laboratory almost 35 years ago.1 Although extensive experimental studies of drag reduction are continuing, the mechanism of drag reduction is not well understood. In spite of this limitation, there is a wide potential application for drag reduction in the oil industry in both production and transportation operations.

Drag reduction, as defined by Savins,2 is the increase in pumpability of a fluid caused by the addition of small amounts of an additive to the fluid. The effectiveness of a drag reducer is normally expressed in terms of percent drag reduction. At a given flow rate, percent drag reduction (DR) is defined asEquation 1

where ?p is the base pressure drop of the untreated fluid and ?pp is the pressure drop of the fluid containing drag-reducing polymer.

Percent drag reduction is a measure of drag-reducing additive performance, but it does not reflect the primary end use of drag reducers. Normally, the increased pumpability is used to increase flow rate without exceeding the safe pressure limits within the flow system. The relationship between percent drag reduction and percent throughput increase (TI) can be estimated using the following equation.3Equation 2

where %DR is the percent drag reduction as defined in Eq. 1. Eq. 2 assumes that pressure drop for both the treated and untreated fluid is proportional to flow rate raised to the 1.8 power.

The volumetric capacity and/or horsepower of the existing pumps may limit the amount of throughput increase. The installations of additional pump capacity may be necessary to obtain the full benefits of drag reducer use.

The use of drag reducers in the oil industry has been limited primarily to hydraulic fracturing operations.4 Water-soluble polymers have been effective in reducing hydraulic horsepower requirements and/or increasing pump rates during fracturing treatments. Many water gels used to improve the sand-carrying capacity of the fracture fluid have excellent drag-reduction properties. Oil-soluble polymers have been used to a lesser extent in hydraulic fracturing with oil-base fluids. Drag reducers have not been used routinely in standard crude oil pipeline operations.
A Successful Peripheral Water Flood in a Thin Pennsylvanian Reservoir
Authors: Wattenbarger R.A. , Howell B.L. , Loye P.E.
Published: December 2007

The Northeast Jones area of Oklahoma was discovered in 1945. Production peaked in 1948 and the area was almost depleted by 1950. Primary recovery was an economic failure and the field was almost abandoned without a trial of secondary recovery. There were several reasons for the pessimism regarding water flooding, but the most predominant was the old "rule of thumb" that secondary recovery would be the same as primary recovery. The Northeast Jones Cleveland sand unit was formed in 1952, however, with the promotion of an outside group of operators. The water flood proved to be very successful and lucrative, recovering over twice as much waterflood oil as primary oil. Peripheral injection was employed which eliminated the need to drill new wells and, in retrospect, made the project much more successful than would have a pattern water flood. The geometry of the water flood, the uniformity of the formation, and the high oil saturation are believed to be the major contributing factors to the high waterflood recovery and efficiency. Only 3.1 bbl of effective water injection were required for each barrel of oil recovered.

Introduction

Often, in engineering a prospective water flood, it is found that neither the data nor the applicable calculation methods are completely adequate. To some extent, previous experience is applied in these cases and comparisons are made to known field case histories. When the fields are, in fact, comparable, the predictions are valid. However, many times comparisons or rules of thumb are not valid and the results can be very expensive. In the case of the Northeast Jones, some operators had condemned water flooding because of poor primary recovery, using the old "rule of thumb" that waterflood recovery would approximate primary recovery. The area came close to being abandoned without secondary recovery, but a unit was finally formed and water flooding was very successful. Undoubtedly, if present waterflooding experience had been available at the time of decision on the Northeast Jones, there would not have been much doubt regarding water flooding. The value of case histories, then, is in providing an ample range of experiences so that valid comparisons can be made by the engineer for the purpose of prediction. This paper presents an analysis of the history, planning and performance of the Northeast Jones water flood.

Reservoir Development and Characteristics

The Jones Field, shown in Fig. 1, is composed of the Northeast Jones and West Jones areas. Each of these areas was originally considered as a separate field but production performance showed that they should be considered as one. The two areas are in communication but are partially separated by a permeability pinch-out in Section 27.The Cleveland sand reservoir is a stratigraphic trap of Pennsylvanian marine deposition. The reservoir is 4,600 ft deep and its producing thickness varies from 4 to 9 ft, averaging 6.5 ft.

JPT

P. 1238ˆ
Estimation of Tertiary Recovery by CO2 Injection - Springer A Sand, Northeast Purdy Unit
Authors: Simlote Vishnu , Withjack Eric M.
Published: December 2007

Introduction

The northeast Purdy Springer A sand reservoir is in Garvin County, OK (Fig. 1). The original oil in place (OOIP) was approximately 225 million STB (35.8 × 10 stock-tank m). Primary production from the field began in 1951. The waterflood was developed in three stages from 1960 through 1963. Cumulative oil production through 1977 was 79.5 million STB (I 2.6 × 10 stock-tank M); thus, the possible additional oil available for enhanced recovery is significant. The purpose of this work is to evaluate the potential of tertiary CO2 flooding in the reservoir. The representation of reservoir heterogeneity and the distribution of remaining oil saturation are extremely important to the calculation of oil recovery expected from CO2 flooding. Much effort was devoted to describing the reservoir heterogeneity. The reservoir characteristics were developed from a detailed geological study of depositional environment, log interpretations, core analyses, and pressure transient data. The large number of wells and limited reliable individual-well production data precluded simulation of the entire field. Therefore, a typical-pattern approach using average field properties was selected. This paper first presents the approach used in simulating primary production and the three stages of waterflooding. The method used to evaluate CO2 flooding is presented next, with emphasis on oil recovery sensitivity to the various flood design parameters. These include CO2 slug size, WAG ratio, and well spacing.

Field History

The initial pressure of the Springer A reservoir was 3,050 psig (21 MPa) at 8,200 ft (2500 m) subsea. The pressure declined to a minimum of about 900 psig (6.2 MPa) in 1964 and then increased as a result of water injection. Current average pressure in the reservoir is about 2,000 psig (13.8 MPa). Initial saturation pressure of the oil was estimated to be 2,785 psig (19.2 MPa), and the initial solution GOR was estimated to be 724 scf/STB (129 std m / stocktank m). The original PVT data are given in Table 1. Current average producing GOR is about 400 scf/STB (71.3 std m /stock-tank M), and the producing WOR is about 10:1.

Geological Description

The Springer A reservoir contains Lower Pennsylvanian rocks deposited as shallow marine sediments with environmental variations. The sand is a fine-to medium-grained siliceous sandstone dipping approximately 8 degrees southwest. Fig. 2 is a three-dimensional (3D) map showing the reservoir configuration. Data from core analyses indicate numerous tight zones within the gross pay section. Some cores show more than one well-defined pay zone, while others indicate only a single zone.

JPT

P. 808^
Peripheral Pattern Waterflood Performance, Sholem Alechem Fault Block "E" Unit
Authors: Denham Ralph R.
Published: December 2007

Predictions of primary performance and five-spot water-flood performance were made early in the life of the Sholem Alechem fault block "E" field. A fieldwide secondary-recovery unit was formed near the end of primary depletion and the reservoir was water flooded using a peripheral injection pattern. By comparing the five-spot waterflood prediction with the actual peripheral waterflood performance, we established that five-spot predictions of oil recovery, water production and water injection can be used to determine the same performance characteristics throughout the life of a peripheral water flood. Accomplishing and determining fill-up are necessary for the satisfactory operation of a peripheral water flood in a previously depleted reservoir. Methods of positively determining fill-up as well as inconclusive indications of fill-up are discussed. After fill-up it is possible to make a pore-volume calculation of waterflood reserves utilizing flood-front data and new saturation conditions, which will serve as a check on the previous estimates of waterflood reserves.

Introduction

The Springer Sims sand reservoir in the fault block "E" area was initially produced in 1948. The reservoir was developed on 10-acre spacing, and the unitized area includes 47 wells. Reservoir characteristics are included on Table 1.The reservoir is a portion of the Springer anticline structure, which has been separated by major faulting. A combination of normal block faulting followed later by reverse faulting together with sand development has divided the area into several essentially closed reservoirs. The Sholem Alechem fault block "E" unit (SAFBEU) was formed from the oil-producing portion of an essentially separate reservoir. The area is closed on the north by a fault and sand development, on the west by a fault. on the east by sand development and on the south by a water-oil contact. This is shown in Fig. 1.The reservoir originally had a gas cap and an aquifer. During primary depletion the reservoir produced principally as dissolved-gas-drive reservoir with some gas-cap expansion. Although some water was produced from down-dip wells and there was a noticeable encroachment of water before unitized operations began. there was no appreciable recovery resulting from the water influx. During 1953 the unitization engineering subcommittee evaluated primary and five-spot waterflood performance for the proposed unit area. These predictions and actual production during the primary and waterflood phases of operation are shown on Fig. 2.

JPT

P. 537ˆ
Restoration of Groundwater Quality Following Pilot-Scale Acidic In-Situ Uranium Leaching at Nine-Mile Lake Site Near Casper, Wyoming
Authors: Engelmann William H. , Phillips P. E. , Tweeton Daryl R. , Loest Kent W. , Nigbor Michael T.
Published: December 2007

The results of the first restoration effort for a pilot-scale acidic leaching of a uranium ore body in the U.S. are given. The project was performed under a cooperative agreement between the USBM and a joint venture consisting of Rocky Mountain Energy, Mono Power Co., and Halliburton Co. The leaching phase is described only briefly; it was reported earlier by Tweeton et al.1 Leaching was done with H2SO4 (pH range of 1.6 to 3.9) and H2O2 (80 to 1,000 ppm) over an 11-month period.

The restoration phase began in September 1978 and was completed in 11 months. Water samples were taken from observation wells located between injection and production wells while the leaching solution was decreased in strength. Groundwater quality in the leached ore zone was restored by diluting and neutralizing effects of injecting native groundwater and treated water produced from recovered solution. Recovered water was purified by a combination of chemical precipitation and reverse osmosis. In-situ measurements of pH, Eh, dissolved oxygen, conductivity, and temperature were made by a downhole probe in one of the wells. Water samples were taken and analyzed for U, V, Na. K, Ca, Mg, SO4. P, Cl, F, Fe, Mn, Si, Zn, As, and Se.
Use of Hydraulic Fracturing Equipment for Formation Sand Control
Authors: Rawlings H. Earl
Published: December 2007

Introduction

Beginning early in the history of producing oil from subsurface strata, the industry has been constantly searching for efficient economical means of controlling the movement of unconsolidated formations into the wellbore. During the past 25 years, numerous investigations of various gravel screening media and their characteristics have been very satisfactorily carried out, demonstrating to the industry that sand or gravel properly selected and placed can effect formation sand control and not damage productivity. In the past years the use of gravel in wellbores for this purpose has met with varying success.

Gravel or sand size selection for various formation conditions has been previously investigated.

Early research and field applications of a gravel screening medium to unconsolidated oil-bearing sands were confined to only the problem of controlling the movement of these sands into the wellbore. It was early recognized that the more firmly such a screening medium could be placed against a producing formation, the more successful the pack would be in controlling movement. A satisfactory method and equipment for placing the packing material under pressure has long been desired.

The mechanics of strata penetrated by wellbores have been under study for many years. Some of the developed theories vary even with ideal matrix. The unconsolidated oil-bearing sands conform to mechanical patterns that are even more highly controversial. The most common effect of stresses within these formations is movement of the formation particles. Secondary, but notable, is the usual rapid production decline in some of them.

Theory and Practice

Placing packing media against and into unconsolidated oil-bearing sands with pressure, allowing the carrying fluid to be absorbed by the formation being treated, appears to offer many advantages. This pressure technique can often effect a tight full pack which cannot always be realized with washdown methods where forces exercised are only equal to the weight of the packing medium.
Flow Properties of Utah Shale Oils
Authors: Seitzer W. H. , Lovell P. F.
Published: December 2007

In a concentric cylinder viscometer, Utah shale oils have different characteristics, both at equilibrium flow and during start-up from rest, depending on whether the wax has crystallized as needles or spherulites. Compared with waxy crude oils, which are thixotropic, shale oil has the added rheological property of being antithixotropic.
Equations and Type Curves for Predicting the Polymerization of Amorphous Silica in Geothermal Brines
Authors: Weres Oleh , Yee Andrew , Tsao Leon
Published: December 2007

The polymerization of dissolved silica in aqueous solutions up to 100°C and containing up to 1 M NaCl has been studied experimentally, and theoretically. In this paper, the results of this work are presented in a form suitable for practical use in interpreting and predicting the chemistry of silica in geothermal brines. Empirical equations for calculating the rate of molecular deposition of silica on surfaces as a function of silica concentration, temperature, pH, and salinity are presented. Theoretically calculated type curves that depict the decrease of dissolved silica concentration by homogeneous nuclea-tion and particle growth are presented, along with the procedures for using them to predict the course of this process under different conditions.
General Inflow Performance Relationship for Solution-Gas Reservoir Wells
Authors: Dias-Couto Luiz Evanio , Golan Michael
Published: December 2007

Two equations are developed to describe the inflow performance relationship (IPR) of wells producing from solution-gas drive reservoirs. These are general equations (extensions of the currently available IPR's) that apply to wells with any drainage-area shape at any state of completion flow efficiency and any stage of reservoir depletion.

Introduction

The dimensionless IPR presented by Vogel1 was developed for flow of saturated oil from a solution-gas drive reservoir into an "ideal" well (a well without any negative or positive skin effect).

For real wells (damaged or stimulated), Standing2 developed a modification to Vogel's IPR and presented a set of dimensionless curves for a range of flow efficiencies different from one.

An analytical approach for flow efficiency correction of Vogel's IPR that provides a simple equation to calculate the productivities of real wells at present time was presented by Couto.3

Standing4 suggested a simple procedure to obtain the IPR of an ideal well at any future depletion stage.

Applying Couto's approach for flow efficiency correction to Standing's development of future IPR yields a more generalized single IPR equation that accounts for any state of completion flow efficiency and reservoir depletion.

A different approach to predict future IPR of a real well has been proposed by Fetkovich.5 His procedure can be rearranged to yield a single IPR equation somewhat similar to the general equation' derived from Vogel's approach.

Each of the two equations developed may be used to predict future-time IPR of small- to medium-capacity real wells.

Vogel's Present-Time Generalized IPR

According to Vogel, the present-time dimensionless IPR for an ideal well (in which flow efficiency E=1) may be expressed asEquation 1

Substituting the dimensionless bottom hole flowing pressure R=pwf/p in Eq. 1 yieldsEquation 2

Couto has shown that for real wells, in which E?1, Vogel's equation can be written for the ideal part of the pressure drawdown asEquation 3

where p'wf=pwf+Dps is the ideal bottom flowing pressure and j=(p-p'wf)/(p-pwf) is the actual flow efficiency of the real well. Eq. 3 applies for any p'wf/p 0.

Rewriting Eq. 3 in terms of the dimensionless ideal bottom hole flowing pressure R'=p'wf/p, we obtainEquation 4

which applies for any R' 0.
Representing Wells in Numerical Reservoir Simulation: Part 2 – Implementation
Authors: Chappelear John E. , Williamson Alexander S.
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. This paper presents a succinct but comprehensive description of the installation of a well model in a simulator, including problems which may be encountered and possible remedies. This and the preceding paper, SPE 7697, present a unified viewpoint of material, some of which may be already familiar to simulator developers.
The Effect of Interfacial Tensions on Relative Oil/Water Permeabilities of Consolidated Porous Media
Authors: Amaefule Jude O. , Handy Lyman L.
Published: December 2007

Relative permeabilities of systems containing low-tension additives are needed to develop mechanistic insights as to how injected aqueous chemicals affect fluid distribution and flow behavior. This paper presents results of an experimental investigation of the effect of low interfacial tensions (IFT's) on relative oil/water permeabilities of consolidated porous media.

The steady- and unsteady-state displacement methods were used to generate relative permeability curves. Aqueous low-concentration surfactant systems were used to vary IFT levels. Empirical correlations were developed that relate the imbibition relative permeabilities, apparent viscosity, residual oil, and water saturations to the interfacial tension through the capillary number (Nc = vμ/σ). They require two empirical, experimentally generated coefficients.

The experimental results show that the relative oil/water permeabilities at any given saturation are affected substantially by IFT values lower than 10-1 mN/m. Relative oil/water permeabilities increased with decreasing IFT (increasing Nc). The residual oil and residual water saturations (Sor and Swr) decreased, while the total relative mobilities increased with decreasing IFT. The correlations predict values of relative oil/water permeability ratios, fractional flow, and residual saturations that agree with our experimental data. Apparent mobility design viscosities decreased exponentially with the capillary number.

The results of this study can be used with simulators to predict process performance and efficiency for enhanced oil-recovery projects in which chemicals are considered for use either as waterflood or steamflood additives. However, the combined effect of decreased interfacial tension and increased temperature on relative permeabilities has not yet been studied.
Gibbs Energy Analysis of Phase Equilibria
Authors: Baker Lee E. , Pierce Alan C. , Luks Kraemer D.
Published: December 2007

Equations of state are used to predict or to match equilibrium fluid phase behavior for systems as diverse as distillation columns and miscible gas floods of oil reservoirs. The success of such simulations depends on correct predictions of the number and the compositions of phases present at a given temperature, pressure, and overall fluid composition. For example, recent research has shown that three or more phases may exist in equilibrium in CO2 floods.

This paper shows why an equation of state can predict the incorrect number of phases or incorrect phase compositions. The incorrect phase descriptions still satisfy the usual restrictions on equality of chemical potentials of components in each phase and conservation of moles in the system. A new method and its mathematical proof are presented for determining when a phase equilibrium solution is incorrect.

Examples of instances where incorrect predictions may be made are described. These include a binary system in which a two-phase solution may be predicted for a single-phase fluid and a multicomponent CO2/reservoir oil system in which three or more phases may coexist.
Surfactant Flooding 2: The Effect of Alkaline Additives on Permeability and Sweep Efficiency
Authors: Krumrine Paul H. , Falcone James S. , Campbell Thomas C.
Published: December 2007

This paper is the second of a series of papers reporting our examinations of the effects alkaline additives have on dilute surfactant systems for low-tension waterflooding (LTWF). The first paper outlined the effects on interfacial tension (IFT), hardness removal, and surfactant retention by the core material, and how these parameters then affect overall recovery of oil from watered-out cores containing high-hardness brines. This study examines the effects of those chemicals on permeability, sweep efficiency, and sweep symmetry through multipermeable noncommunicating zones. Correlations and possible mechanisms are offered that relate these findings to the earlier work on surfactant retention and hardness removal.

The results of these studies indicate that each alkali behaves differently, but all are capable of enhancing the action of the dilute surfactant treatment. Sweep efficiency in three-dimensional (3D) patterns and sweep symmetry through multipermeable noncommunicating zones is increased by the alkaline chemicals. Selective permeability reduction, caused by the reaction with the residual hardness ions, is suspected as a mechanism. Overall, sodium silicate addition to the surfactant flood as a builder was found to produce the best performance because of its ability to inhibit surfactant retention, thereby increasing the recovery of crude before selective permeability reduction occurs. Overall permeability loss is only about 20 to 25% in a core initially containing 4,800 ppm of hardness as CaCOз under our experimental conditions.
Temperature Observations and Steam-Zone Rise in the Vicinity of a Steam-Heated Fracture
Authors: Closmann Philip J. , Smith Richard A.
Published: December 2007

Temperature observations taken in a well that traverses a steam-heated fracture in a tar sand formation allow estimates of the in-situ thermal parameters of the formation. They also indicate for the case presented the upward movement of a heat source at a constant velocity, suggesting the vertical growth of a permeable hot zone. This vertical movement can be modeled approximately with a thermal simulator. Comparison of numerical and analytic solutions, however, shows that very small finite-difference grid spacing is required to obtain the correct steam rise velocity with the simulator. The comparison between experimental and simulation results also provides an indication of the relative importance of the vertical reservoir permeability.
Vapor-Pressure Lowering in Geothermal Systems
Authors: Hsieh Chih-Hang , Ramey Henry J.
Published: December 2007

The water vapor-pressure lowering phenomenon in porous media was investigated for a range of temperatures by measuring vapor pressure vs. mass of water adsorbed in consolidated sandstone cores and unconsolidated silica sands. Experimental results showed that the mass of water adsorbed on the rock surface is much more than the amount of pore steam. Results also revealed that the water adsorption is caused mainly by micropores in the porous medium. Measurement of the mass of methane and ethane adsorbed on dry rocks showed that the amount of adsorption is not great in comparison with the pore gas.

It was found that adsorption data for water/sandstone core studies could be normalized with respect to temperature. Although this appears not to have been reported previously, it does agree in principle with findings for solid powders with micropores. Another interesting result was that reanalysis of previous studies of capillarity in sandstones indicates that experimental data probably were influenced mostly by adsorption.
Correlation of Crude Oil Steam Distillation Yields With Basic Crude Oil Properties
Authors: Wu Ching H. , Elder Robert B.
Published: December 2007

Steam distillation can occur in reservoirs during steam injection and in-situ combustion processes. To estimate the amount of vaporized oil caused by steam distillation, we established correlations of steam distillation yields with the basic crude oil properties. These correlations were based on steam distillation tests performed on 16 crude oils from various parts of the U.S. The gravity of oils varied from 12 to 40°API [0.99 to 0.83 g/cm3]. The viscosity of oil ranged from 5 to 4,085 cSt [5 to 4085 mm2/s] at 100°F [38°C]. The steam distillations were performed at a saturated steam pressure of 220 psia [1.5 MPa]. One oil sample was used in experiments to investigate the effect of steam pressure (220 to 500 psia [1.5 to 3.4 MPa]) on the steam distillation yield.

The experiments were carried out to a steam distillation factor (Vw/Voi) of 20, with the factor defined as the cumulative volume of condensed steam used in distillation, Vw, divided by the initial volume of oil, Voi. At a steam distillation factor of 20, the distillation yields ranged from 13 to 57% of the initial oil volume.

Several basic crude oil properties can be used to predict steam distillation yields reasonably well. A correlation using oil viscosity in centistokes at 100°F [38°C] can be used to predict the steam distillation yield within a standard error of 4.3%. The API gravity can be used to estimate yields within 5.6%. A gas chromatographic analysis was made for each crude oil to obtain the component boiling points (simulated distillation temperatures). A correlation parameter was selected from the simulated distillation results that can be used to estimate the steam distillation yields within 4.5%.
A New Method To Measure Directional Permeability
Authors: Rose Walter D.
Published: December 2007

Introduction and Theory

The problem of measuring directional permeability by applying Darcy's law has been known for a long time, but so far it has been left unresolved. Here we show that for two-dimensional cases of anisotropy, three measurements must be made on a laboratory sample to calculate the maximum and minimum permeability from the data. These are (1) Angle B, which shows the direction of flow with respect to the direction of maximum permeability, (2) Angle A, which shows the direction of permeability, (2) Angle A, which shows the direction of flow with respect to the direction of the driving force gradient, and (3) the R11 element of the resistivity tensor that appears when Darcy's law is given the special form

Rij qu=-grad p................... (1)

Here Rij is the second-rank (symmetric) resistivity tensor defined by the transformation rule

(2)

In Eq. 2, lambda ii and lambda jj are the direction cosines between an i, j-axis frame and any other i, j- (rotated-) axis frame. Specifically, it is clear that an angle, - B, always can be found such that Rij will take on a diagonalized form.

It and easy to prove that the inverses of R1 and R2, respectively, give the maximum and minimum Darcian permeabilities since the i, j-axis frame coincides with the permeabilities since the i, j-axis frame coincides with the principal directions of the permeability tensor. principal directions of the permeability tensor. JPT

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