bluuebunny/crossref_metadata_2025 huggingface dataset:
Comparative Energy Requirements of Oilfield Pumping Units--Conventional vs Front-Mounted
Authors: Patton L. Douglas
Published: December 2007

Conventional front-mounted, rotary crank-balanced pumping units were compared with front-mounted pumps to determine the comparative electric energy requirements. The wells studied were divided into groups of identical make, API ratings, strokes per minute and stroke length. Monthly production and power consumption were averaged for a six-month period and kilowatt- hours per barrel of fluid per 1,000 ft of depth were calculated and plotted against fluid production per day. The front-mounted units consumed an average of 36.8 per cent less electric power than did the conventional units when the strokes per minute were scaled evenly. Design modifications of the front-mounted units are discussed and dynagraph cards are used to illustrate the work loads.

Introduction

A number of major oil companies have made comparative field tests of the front-mounted, rotary crank- balanced pumping unit (Fig. 1) and various conventional beam-type pumping units (Fig. 2). These tests were generally made using one type of unit on a given well for several days then replacing it with the other type unit for the same length of time. The daily production, electric energy used and inch-pounds of torque required were all noted during these exacting tests. Obviously a study of this type requires more time and money than are generally available to most companies. Another method of comparing the conventional beam- type pumping unit with the front-mounted, rotary crank- balanced pumping unit, based on electric energy consumed per barrel of fluid pumped, is discussed in this paper. The wells under study were divided into groups of identical make, API ratings, strokes per minute and stroke length:

conventional 160D units operating at 16.5 X 64 in. strokes/min; conventional 160D units operating at 16.3 X 64 in. strokes/min; and front- mounted 114D units operating at 16.7 X 64 in. strokes/ min.

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P. 26ˆ
Fluid-Loss Control Through the Use of a Liquid-Thickened Completion and Workover Brine
Authors: Hudson T.E. , Coffey M.D. , Sauer C.W. , Teot A.S.
Published: December 2007

A new liquid thickening agent has been developed for controlling fluid loss of clear brines. This control is of critical concern during the completion or workover of an oil, gas, or service well.

Many clear brines are expensive (up to $800/bbl for some concentrations). The loss of these fluids to the formation can become a significant completion/workover expense. From a safety standpoint, the loss of clear brines to a formation may create a reduction in hydrostatic pressure, which would increase the potential of a well kick or blowout.

The newly developed agents function in brines with densities from 9.1 to 19.2 lbm/gal. They are superior to the traditionally used polymer because they start to build viscosity instantly, without the formation of "fish eye"s. The viscosity developed in the clear brines through the addition of these materials can be broken easily at the surface by the addition of small amounts of commonly available breakers. Brines containing this polymer show little or no permanent return permeability damage. The properties of the materials as fluid-loss-control additives in clear brines, their nondamaging characteristics, and rheological properties of the thickened brines are described. Case histories support the advantages of these properties.

Introduction

Fluid-loss control of clear brines is of primary concern during the completion or workover stage of an oil, gas, or injection well. The clear brines used in completions and workovers typically contain KCl, NaCl, CaCl2, CaBr2, and ZnBr2, or combinations of these salts, and range in density from 8.4 to 19.2 lbm/gal. These brines cost from a few dollars for the least-dense brine to about $800 for a 19.2-lbm/gal brine. The loss of these relatively high-cost, clear brines to the formation can be of significant importance when attempts are made to minimize completion and workover expenses. Loss of fluid level, resulting in a decrease of hydrostatic pressure on the formation, which exposes the rig and personnel to the danger of a well kick or blowout. Fluid-loss-control mechanisms when clear brines are in use have traditionally included (1) reducing the density of the completion or workover fluid, thereby imposing less hydrostatic pressure on the formation, (2) adding solids such as graded CaCO3 particles, FeCO3 particles, or sized rock salt, and (3) increasing the viscosity of the clear brines by adding dry polymers such as guar gum, hydroxylpropyl guar, xanthan gum, and (most commonly) hydroxyethylcellulose (HEC). These methods have been used independently and in combination with one another.1–4
Experimental Study of Drilled Cuttings Transport Using Common Drilling Muds
Authors: Hussaini Syed M. , Azar Jamal J.
Published: December 2007

Experiments are conducted with actual drilling muds to study the behavior of drilled cuttings in a vertical annulus. The effect of parameters such as particle size, flow rate, apparent viscosity, and yield point to plastic viscosity ratio on mud-carrying capacity are studied. The applicability of a semiempirical transport model developed by Zeidler also is investigated.

It has been shown that in vertical annuluses, the fluid annular velocity has a major effect on the carrying capacity of muds, while the other parameters have an effect only at low to medium fluid annular velocities. We also conclude that Zeidler's semiempirical formulations for the prediction of drilled cuttings behavior are valid with certain limitations.
The Phase Behavior of Simple Salt-Tolerant Sulfonates
Authors: Barakat Y. , Fortney L. N. , LaLanne-Cassou C. , Schechter R. S. , Wade W. H. , Weerasooriya U. , Yiv S.
Published: December 2007

Alkane and α-olefin sulfonates can be used to produce optimal microemulsion formulations having very high salinity tolerance (including divalent ion) while maintaining large solubilization parameters and low inter-facial tensions (IFT's). Such molecules require elevated temperatures or higher alcohol concentrations to suppress liquid crystal formation. As in other species, solubilization is inversely related to width of the three-phase regime, and IFT and solubilization are strongly coupled.
Effect of Rates on Performance in Browning Unit Water Flood
Authors: Wright F.F.
Published: December 2007

A brief history of the Browning Unit waterflood project in Greenwood County, Kans., is presented in which both slow and high injection rates have been used. The pilot area which was subjected to six years of slow injection rates followed by high injection rates is analyzed. It is concluded that performance has been more satisfactory at the higher rates of injection.

Introduction

The Browning Unit is a pattern-type flood operated by Sinclair Oil & Gas Co. Other members of the unit include Tidewater Oil Co., Sunray Mid-Continent Oil Co., Dover Corp., C. A. Steele, Irma Rosenthal and David M. Rhodes Estate. Because of the variance in waterflooding rates applied during the past eight years, much interest in the performance has developed.

Geology

The Bartlesville sand of Pennsylvanian age is found at approximately 2,300 ft in a lens-shaped body apparently deposited as an offshore bar. The unit lies in a definite trend of shoestring development of the Bartlesville sand. Figs. 1 and 2 show core graphs of the Bartlesville sand on the Browning Unit. Table 1 gives other information concerning this reservoir.

Primary Production

Fig. 3 gives the oil production history of the unit since its development in 1924. In addition, Fig. 4 shows a pre-unit history on a typical part of the Browning Unit. At the start of the water flood the primary oil was essentially depleted.

Gas Repressuring

In 1928 a program of gas repressuring was started which recovered an estimated 3 million bbl of oil.
An Investigation of Phase-Behavior/Macroscopic-Bypassing Interaction in CO2 Flooding
Authors: Gardner J. W. , Ypma J. G. J.
Published: December 2007

CO2 core floods and related high-resolution, mathematical simulations in which viscous fingering is represented explicitly indicate a synergistic interaction between multicontact CO2/crude phase behavior and macroscopic bypassing that causes ultimate oil recovery (when the system has been swept) to be lower in unstable displacements than in stable ones. If this effect is present in field applications, corefloods in which fingering is absent should not be used as direct indicators of field-scale CO2 flood displacement efficiency because they will yield optimistic predictions, all other factors being equal in the laboratory and the field.
Interpretation of Differential Pressure in Laboratory Surfactant/Polymer Displacements
Authors: McCool C. Stanley , Parmeswar Ravi , Willhite G. Paul
Published: December 2007

Experimental data were obtained for two surfactant/polymer systems in which fluid mobilities and mobility control were studied through the analysis of differential pressure measurements. One system used nonane as the hydrocarbon phase, while the other system used crude oil from the Madison field, Greenwood County, KS. During the experimental studies, capillary-pressure effects were observed in differential pressure data when floods were conducted at reservoir rates and small port spacing. Capillary-pressure effects interfered with the measurement of the "true" or viscous pressure drop in oil/water banks and the transition region between the oil/water bank and surfactant slug. Pressure ports were designed to permit injection of small quantities of fluid at the rock surface during displacements to verify and to eliminate capillary-pressure effects.

Movement of fluid regions through the core was inferred from the differential pressure measurements along the core. Similar pressure perturbations at the ports were extrapolated to the end of the core and correlated with effluent fractions. In the nonane system, the microemulsion surfactant slug changed to a more mobile macroemulsion within the first half of the displacement. This macroemulsion moved through the last half of the core as a stabilized, constant velocity bank indicating good mobility control even though the apparent viscosity of the macroemulsion was less than that of the stabilized oil/water bank. In the crude-oil surfactant system, pressure data collected along the core indicated capillary-pressure effects at the leading edge of the oil bank and the formation of a viscous, less mobile region resulting from mixing of the microemulsion slug with resident fluids. Phase-behavior studies indicated the formation of a viscous lower phase as the microemulsion was diluted with brine. The formation and propagation of this viscous region during displacement leads to favorable mobility control illustrated by the pressure/ mobility curves as well as by good oil recoveries (80 to 95%).
Equilibrium Phase Compositions of CO2/Crude Oil Mixtures—Part 2: Comparison of Continuous Multiple-Contact and Slim-Tube Displacement Tests
Authors: Orr Franklin M. , Silva Matthew K. , Lien Cheng-Li
Published: December 2007

Results of phase composition and density measurements for CO2/crude-oil mixtures at 32°C and four pressures are reported for a system in which liquid/liquid and liquid/liquid/vapor phase separations occur. The experiments demonstrate that a CO2-rich liquid phase can contain as much as 30 wt% hydrocarbons and show that a CO2-rich vapor phase at the same conditions extracts hydrocarbons less efficiently. Pseudoternary phase diagrams are presented that summarize the results of the detailed phase composition measurements.

Results of slim-tube displacements at the same four pressures are also given. They indicate that displacement is efficient when the pressure is high enough that a liquid CO2-rich phase appears.

Predictions of the performance of the slim-tube displacements based entirely on the experimental measurements of phase compositions and densities are obtained using a simple one-dimensional (1D) simulator. The simulation results clarify the roles of phase behavior and volume change on mixing in the siim-tube tests.

Finally, the advantages and limitations of the slim-tube and continuous multiple-contact (CMC) tests are compared. We conclude that the CMC experiment yields more information useful for prediction of the performance of a CO2 flood.
Equilibrium Phase Compositions of CO2/Hydrocarbon Mixtures— Part 1: Measurement by a Continuous Multiple-Contact Experiment
Authors: Orr Franklin M. , Silva Matthew K.
Published: December 2007

A new experimental technique that simultaneously measures compositions and densities of two phases in equilibrium is described. Because it operates continuously, the experiment can be performed more rapidly than conventional static-equilibrium measurements. Details of the experimental apparatus are reported, and results of test displacements for two simple CO2/hydrocarbon systems are compared with static-equilibrium phase composition measurements for the same systems. A simple analysis of the operation of the experiment is used to assess the experimental error that results from the continuous nature of the experiment and to suggest ways to reduce that error. Application of the experimental technique to a CO2/crude oil system is reported in a companion paper.1
Evaluation of an In-Situ Combustion Process by Postburn Core and Log Analysis
Authors: Joseph Conrad , Jay Charley B. , Eslinger Eric V.
Published: December 2007

Evaluation of the performance of an in-situ combustion process applied by Cities Service Co. in the Bellevue field was made possible by analysis of postburn cores and logs from wells drilled within the flooded zone. postburn cores and logs from wells drilled within the flooded zone. Temperature-observation-well data and production performance were inadequate to describe the coverage and efficiency of the simultaneous air- and water-injection method applied.

Introduction

An attempt was made to monitor the coverage of the burn fronts generated by five injection wells in the Bellevue field using one temperature-observation well per injector. After 4 years' continuous injection, only one observation well ever had shown the high temperatures seen in laboratory combustion tube studies, and an accurate description of the burned zone could not be determined. After air injection was terminated, four wells were drilled within one pattern, obtaining openhole logs and cores of the producing formation. pattern, obtaining openhole logs and cores of the producing formation. Results from this postburn drilling program were used in constructing an approximate burned zone for the pattern, enabling better understanding of the combustion process and of the efficiency of the field project.

Reservoir and Laboratory Data

The combustion project is being conducted in the Bellevue field of northwestern Louisiana. This field, discovered in 1921, produces a 19API (0.9 g/cm3) crude from the Upper Cretaceous Nacatoch sand. Primary production from the field is estimated to have been less than 15% of the production from the field is estimated to have been less than 15% of the original oil in place (OOIP). The field is a 900-acre (4 × 10 6 m2) low-relief dome with pay thickness controlled by a water/oil transition at 212 ft. (64.6 m) subsea. The project area covered by this report is a 19-acre (77 × 10 3-m2) five-pattern demonstration conducted by Cities Service Co. under a cost-sharing contract with the U.S. DOE (Contract DE-AC03-76ET12057). In this area of the field the top of the Nacatoch is encountered between 109 and 174 ft (33.2 and 53.0 m) subsea, with dip to the northeast at 4.5 0. At this shallow depth, the Nacatoch is a highly unconsolidated sand with numerous thin, dense, fossiliferous limestone layers. These limestone layers are identified easily from bulk-density logs (Fig. 1) and essentially subdivide the pay section into four principal sand intervals (S1, S2, S3, and S4). The average porosity and permeability of the sand intervals are 33.9% and 700 md, with the sand having a 27.4% water saturation. Average reservoir pressure is only 40 psig (280 kPa).

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p. 827
Critical Scaling Behavior of Microemulsion Systems
Authors: Huang John S. , Kim Mahn Won
Published: December 2007

We used dynamic light scattering to study the characteristic droplet size, r̄, in dilute single-phase microemulsions near the critical phase transition point. We found that there existed a general power-law dependence of r̄ on the reduced variable ΔZ=Zc−Z. Here Z stands for any thermodynamic and system variables whose critical value is denoted by Zc. The variables of interest in the present work are temperature and alkane carbon number (ACN). It is found that r̄∝ΔZ−ν where ν =0.75±0.1. This is observed both in water- and oil-internal microemulsions, independent of the surfactant properties.

This behavior, known as the scaling behavior, was analyzed in terms of generalized homogeneous functions with v as the degree of homogeneity. It turns out that only one of the reduced variables is an independent variable in these functions, greatly simplifying the description of the properties of microemulsions in the neighborhood of a critical phase boundary.
Fluid Flow and Structural Response Modeling Associated With the Mechanics of Hydraulic Fracturing
Authors: Advani Sunder H. , Lee June K. , Khattab Hussein A. , Gurdogan Oguzhan
Published: December 2007

A review of hydraulic-fracture modeling is given. Equations governing pertinent fluid-flow, structural, and fracture-mechanics responses are presented. The finite-element method is used to discretize the field equations and to compute the fracture dimensions, fluid leakoff, and stress intensity factors. In addition, the effects of fracture-fluid properties, layered strata, and in-situ stresses are characterized, and numerical examples are presented.
Helical Postbuckling Configuration of a Weightless Column Under the Action of an Axial Load
Authors: Cheatham John B. , Pattillo Phillip D.
Published: December 2007

The helical postbuckled configuration of a weightless, circular column confined within a cylinder was used by Lubinski et al. in 1962 to develop frequently applied equations describing the deformation of oilfield tubing.1 This paper presents an extension of their work in the form of another expression for the relation between applied force and helical pitch in the buckled state. Based on simple laboratory experiments and stability arguments it appears that the previous force-pitch equation applies during load application and the one given in this paper applies during unloading.
Packing and Drafting in Natural Gas Pipelines
Authors: de Nevers Noel , Day Anthony
Published: December 2007

Increasing and decreasing natural gas pipeline inventory (" packing" and "drafting" ) are examined mathematically. Any line segment's unsteady-state packing or drafting behavior depends on only two dimensionless parameters, packing or drafting behavior depends on only two dimensionless parameters, ( ) and ( ). The influence of ( ) is small, so that for any value of ( ) the behavior of all pipelines can be represented on a single plot; four such plots are shown for four different boundary conditions.

Introduction

Natural gas dispatchers use increase and decrease of the stored inventory of gas in their pipes as one method of matching time-varying demands with supplies, which generally have less time variation. In pipeline terminology, increasing the inventory (and hence the pressure) is called "line packing," while decreasing it is called "line drafting." This paper examines the limits of this procedure, asking both how much gas can be added to or subtracted from the inventory in a given pipeline segment, and how rapidly this can be accomplished.

How Rapidly Can the Inventory Be Depleted or Restored?

Although the questions of how large the inventory is and how much can be taken from it for any change in steady-state conditions can be answered very simply, the computation of how rapidly this can be accomplished requires a set of coupled partial differential equations and a numerical solution on a computer. Fortunately, as shown here, the nondimensional results can be summarized in ways that are fairly easy to use.

Mathematical Theory

It has been known since at least 1951 that the mathematical description of the unsteady-state flow of any gas in a long pipeline is governed by a material-balance equation,

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

and a momentum-balance equation,

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

The mass-balance and momentum equations, expressed with pressure, and mass flow rate, as dependent variables and length, and time, as independent variables and assuming that 's are much smaller than 's and ( / )'s, are

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

and

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

respectively. The justification for dropping the terms as being much smaller than the others is that changes very slowly with changes in and other variables.

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p. 655
Oil Recovery by Heat From In Situ Combustion
Authors: Breston Joseph N.
Published: December 2007

This paper presents a comprehensive and up-to-date review of the mechanics, operating variables and probable economics of the in situ combustion method of oil recovery. It distinguishes between the continuous burning and "heat wave" processes, and points out some of the advantages and disadvantages of each.

Although several useful papers have been published on the results of laboratory experiments, information on the results of field tests has been only fragmentary. In order to present a coherent picture of the present status of the in situ combustion method of oil recovery, the author has combined unofficial information on field tests with laboratory data to present some figures-at least some "ball park averages", for petroleum technologists who might be considering a trial of the process.

Introduction

In situ combustion basically consists of igniting the oil in porous reservoir rock with a suitable ignitor and driving a combustion zone through the reservoir toward producing wells with compressed air, with or without recycle gas. This process differs from other thermal processes in which heat is generated at the surface and injected into the reservoir via hot water, gases, or steam.

The in situ principle appeared in 1923 (first U.S. patent) and since 1948 10 field experiments have been conducted in various parts of the U.S., Canada and South America, including one test in Colorado oil shales. Approximately 10 pilot tests are currently being conducted and large commercial operations are planned by several companies.

Mechanism

During an in situ operation very little reservoir oil is consumed for the combustion front creates hot gases which force oil and water to producing wells. The produced oil is practically unaltered since it is not subjected to cracking temperatures. Actually, during most of the life of the operation, the fluids entering the producing wells are at or near the original reservoir temperature. Fig. 1 shows four coexistent but distinct transient regions which exist between the injection and producing wells.
The Static and Dynamic Interfacial Tensions Between Crude Oils and Caustic Solutions
Authors: Trujillo Edward M.
Published: December 2007

One method to achieve EOR is chemical alteration of the reservoir environment so that previously trapped oil can begin to flow freely. Under certain conditions, caustic or alkaline solutions can do this. The work reported here shows that interfacial tension (IFT) between various crudes and caustics increases with time because of desorption of the surface-active species from the interface. The desorption rate is temperature-dependent. Four kinds of crude oil were used—a California crude, a Wyoming crude, an Illinois crude, and an Alaska crude. Only with crude oils with a high concentration of crude acids, such as the California crude, is the ultralow IFT maintained for any reasonable period of time, namely 24 hours. The presence of calcium ions at concentrations of 200 ppm or more destroys the capability of caustic to reduce the IFT's, even for the California crude.

Mass-action relationships are presented that describe the equilibrium IFT at constant ionic strength between crude oils and sodium hydroxide solutions as a function of pH and calcium. Techniques are presented for evaluating time-dependent IFT's obtained by the spinning-drop apparatus. A transient mathematical model shows that IFT can increase by several orders of magnitude over a period of several days. Good agreement between the model and experimental data is obtained. The parameters obtained from these mathematical models describe crude reactivity to caustic more accurately than conventional crude acid numbers. The transient effects observed in the laboratory may or may not be significant in the field.
Microcrack Permeability in Tight Gas Sandstone
Authors: Ostensen R. W.
Published: December 2007

A model of stress-dependent permeability was developed on the basis of flow through cracks. The compliance of the cracks is controlled by elastic deformation of a Gaussian distribution of surface asperities, indented into the opposing crack face. The theory was applied to data from tight gas sand cores, with the following results.

The theory explains the Jones and Owens permeability correlation1 and predicts a modification of it that yields a better fit. The slope of the permeability/stress curve on a log-log plot is predicted to be about 1.0, which agrees with the data. The Jones and Owens Klinkenberg correlation supports a slit-like flow model and indicates that flow occurs along almost every grain boundary. The size of the surface roughness was computed from the Klinkenberg factor and the slope of the permeability/stress curve. It is independent of stress, as predicted by the theory. The porosity of tight sand cores decreases linearly with the log of net confining stress, in accordance with the Walsh-Grosenbaugh model of crack compressibility.

This detailed agreement supports the theory and indicates that the permeability of tight gas sand cores is due to microcracks.
On the Residence Time of Oil Mixed Into the Water Column by Breaking Waves
Authors: Naess Arvid
Published: December 2007

The main purpose of our paper is to present experimental results on the mixing of oil into the water column by breaking waves. During sea states characterized by frequent breaking it is believed that the breaking waves play a dominant role in the natural dispersion of an oil slick. When a breaking wave hits an oil slick, it will cause a mixing of oil into the water column. Because of buoyant effects, the oil particles tend to rise toward the surface again. This leads to a short-term balance between mixing and rising that is determined largely by the characteristic residence times of the oil particles in the water column. This particular problem is the subject of this paper.
Kinetic Study of Desulfonation of Disulfonated Alkyl Diphenyloxide Surfactants
Authors: Marriott R. C. , Kao C. I. , Kristal F. W.
Published: December 2007

Kinetic study of the desulfonation of Dowfax® surfactants, disulfonated alkyl diphenyloxide, is carried out in the temperature range of from 177 to 272°C, and a pH range of 2.0 to 7.0. The rate data support that the desulfonation is a step-wise reaction catalyzed by hydrogen ion. The desulfonation rate is first-order with respect to both surfactant and hydrogen ion concentrations. As a result, the pH of the reaction system has a very significant effect on the stability of the surfactants and may outweigh the effect of temperature. The half-life of disulfonated alkyl diphenyloxide at 235°C in a 5.5-pH buffer solution is 1,035 days, and at 272°C in a 7.0-pH buffer solution is 295 days. The results indicate that these surfactants can be used in most oil reservoir steamflood applications, especially when the rock formation may buffer the pH to about 7.0.
An Electromagnetic Survey Method for Directionally Drilling a Relief Well Into a Blown Out Oil or Gas Well
Authors: Kuckes Arthur F. , Lautzenhiser T. , Nekut A. G. , Sigal R.
Published: December 2007

This paper describes an electromagnetic method to facilitate drilling a well to intersect a target well casing. It has an important application in control of blown out oil and gas wells. By this method, a relief well was directionally drilled to intersect the casing of a blowout at 8,000 ft [2700 m]. The relative distance and azimuthal direction to the target casing can be determined when the relief well is up to more than 100 ft [30 m] from the blowout.
Laboratory Study of Diamond-Bit Hydraulic Lift
Authors: Winters Warren J. , Warren T. M.
Published: December 2007

Hydraulic lift can have a major effect on the operation of diamond drill bits. The actual weight on bit (WOB) is less than the measured weight by the amount of hydraulic lift, or pumpoff force, acting beneath the bit. Pumpoff forces greater than 15,000 lbf [66.7 kN] have been recorded.

Historically, hydraulic lift has been recognized but not understood well enough to be accounted for reliably. The current hydraulic-lift theory has been developed and validated through a series of laboratory tests. Measurement techniques have been reduced to simple procedures for determining any bit's hydraulic-lift effect. Laboratory studies show that under identical conditions, the amount of hydraulic lift varies widely with bit design. Two parameters—the effective pumpoff area and apparent nozzle area—characterize a bit's pumpoff effect and are used to explain and to predict variations in hydraulic lift with diamond bits.
The "Checker Model," An Improvement in Modeling Naturally Fractured Reservoirs With a Tridimensional, Triphasic, Black-Oil Numerical Model
Authors: Bossie-Codreanu Dimitrie , Bia Paul R. , Sabathier Jean-Claude
Published: December 2007

This paper describes an approach to simulating the flow of water, oil, and gas in fully or partially fractured reservoirs with conventional black-oil models. This approach is based on the dual porosity concept and uses a conventional tridimensional, triphasic, black-oil model with minor modifications. The basic feature is an elementary volume of the fractured reservoir that is simulated by several model cells; the matrix is concentrated into one matrix cell and the fractures into the adjacent fracture cells. Fracture cells offer a continuous path for fluid flows, while matrix cells are discontinuous ("checker board" display). The matrix-fracture flows are calculated directly by the model. Limitations and applications of this approximate approach are discussed and examples given.
Laboratory Investigation of the Water-Driven Carbon Dioxide Process for Oil Recovery
Authors: Beeson D.M. , Ortloff G.D.
Published: December 2007

Water-propelled banks of carbon dioxide recovered both high- and low-viscosity crude oil substantially in excess of that recovered by water flood in linear flow model experiments. The increase in oil recovery is explained by oil swelling and viscosity reduction. Additional oil was recovered by solution gas drive at the end of the carbon dioxide floods when the model systems were depressured.

Introduction

This study was an investigation of the use of a water-driven carbon dioxide bank to recover crude oil. Techniques involving the injection of carbon dioxide have aroused considerable interest in recent years among methods considered for increasing oil recoveries.

A number of investigators have studied the process in the laboratory and in the field. Laboratory studies referenced indicate that carbon dioxide in conjunction with water flooding recovers more oil than does water flooding alone. These reports diverge widely, however, in stating magnitude of improvement.

We believed that a water-driven carbon dioxide bank would increase recovery of crude oils by two mechanisms: viscosity reduction and oil swelling. Due to reduction in the oil viscosity caused by solution of carbon dioxide, displacement efficiency should be improved. In addition, the residual oil should be highly swollen by the carbon dioxide held in solution. Thus, the final residual oil saturation, in terms of stock-tank oil, would be lower than in the absence of carbon dioxide.

To test this hypothesis, experiments were carried out to recover both high- and low-viscosity crude oils from linear laboratory models. Tests reported here were carried out in small-diameter models at low rates of fluid advance, where diffusion is a powerful factor in preventing fingering or channeling. The volumetric sweep efficiency of the injected fluids should, under these conditions, be close to 100 per cent. In a field operation it would be necessary to evaluate stratification effects and to consider areal sweep efficiency.
Results of Mathematical Modeling of Modified In-Situ Oil Shale Retorting
Authors: Braun R. L. , Diaz J. C , Lewis A. E.
Published: December 2007

Lawrence Livermore Natl. Laboratory (LLNL) has developed a one-dimensional (1D) mathematical model to simulate modified in-situ (MIS) retorting of oil shale. In this paper we discuss application of the model to commercial-scale retorting conditions. The model was tested by comparing calculated values to those measured in experimental retort runs performed at LLNL. There was generally good agreement between the calculated and observed results for oil yield, temperature profiles, and the yields of most gas species. Retorting rates were generally overestimated by as much as 10%. The model is a useful tool for design and control of retort operations and to identify and interpret observations that differ from model predictions.

The model was used to predict the results for MIS retorting on a commercial scale, focusing on larger retorts and larger shale particle sizes than could be investigated experimentally. Retort bed properties, particularly shale composition and particle size, play an important role in determining the recoverable fraction of oil. For a given shale composition, the inlet-gas properties can be selected to help control retort operations and to maximize oil yield. Extreme variations in oil shale grade that may be encountered as a function of depth can be dealt with by appropriate changes in the composition and flow rate of the inlet gas. In addition, we show that substituting oxygen diluted with steam or CO2 (for air or air diluted with steam) can make significant improvements in the heating value of the effluent gas. Finally, we demonstrate the feasibility of retorting through a substantial interval of very low-grade shale.
Two-Phase Flow in Random Network Models of Porous Media
Authors: Koplik J. , Lasseter T. J.
Published: December 2007

To explore how the microscopic geometry of a pore space affects the macroscopic characteristics of fluid flow in porous media, we have used approximate solutions of the Navier-Stokes equations to calculate the flow of two fluids in random networks. The model pore space consists of an array of pores of variable radius connected to a random number of nearest neighbors by throats of variable length and radius. The various size and connectedness distributions may be arbitrarily assigned, as are the wetting characteristics of the two fluids in the pore space. The fluids are assumed to be incompressible, immiscible, Newtonian, and of equal viscosity. In the calculation, we use Stokes flow results for the motion of the individual fluids and incorporate microscopic capillary force by using the Washburn approximation. At any time, the problem is mathematically identical to a random electrical network of resistors, batteries, and diodes. From the numerical solution of the latter, we compute the fluid velocities and saturation rates of change and use a discrete timestepping procedure to follow the subsequent motion. The scale of the computation has restricted us so far to networks of hundreds of pores in two dimensions (2D). Within these limitations, we discuss the dependence of residual oil saturations and interface shapes on network geometry and flow conditions.
Mineralogical Characterization of Uranium Ore To Evaluate In-Situ Leaching Prospects
Authors: Tsui T. -F.
Published: December 2007

Mineralogical studies of ore samples from Mobil uranium properties in Grants mineral belt (NM) revealed a correlation between certain mineralogical characteristics of the ore and its leaching behavior in the laboratory. Mild alkaline carbonate solutions containing dissolved oxygen gas or hydrogen peroxide were used to leach ore samples. Leaching effects of the uranium minerals and reactive gangue material were investigated by comparing the mineralogical characteristics between pre- and postleach samples. Analyses were made by using the X-ray diffraction method, petrographic microscopic, and scanning electron microscopic (SEM) examinations. In one ore trend where uraninite was the principal uranium mineral, studies showed that (1) the majority of uranium minerals was readily accessible to the leachate on a microscopic scale, (2) the predominant, 1-micron [1-µm] size uraninite crystals were dissolved rapidly during leaching, (3) the minor but locally abundant uranium vanadate species was insoluble in mild alkaline carbonate leachate, and (4) pyrite crystals, with dimensions 10 times greater than the uraninite crystallites, showed some surface etchings.

These results indicate that the solubility and microscopic occurrence of uraninite are favorable for high and rapid uranium recovery, while the fraction of uranium contained in the insoluble uranium vanadate phase cannot be recovered under mild leaching conditions. The uraninite apparently dissolved at a much faster rate than pyrite, indicating a favorable initial selectivity of leachate for uranium. Mineralogical studies of the pre-and postleach ore samples correlate well with the laboratory leach tests, which showed 80 to 90% uranium recovery as well as low vanadium and sulfate levels in the effluents.
The Mechanics of Design and Interpretation of Hydraulic Fracture Treatments
Authors: Crittendon Bob C.
Published: December 2007

Introduction

Since formal introduction of hydraulic fracturing to the petroleum industry in 1948, the technique has increased in prominence each year until in many areas it is now the most popular method of well stimulation. In some areas it is the only technique which will effect commercial production; even some limestone formations which refuse to respond to multiple-stage acid treatments will, subsequent to hydraulic fracture treatments, make commercial wells.

Many theories have been expounded to define conditions associated with hydraulic fracturing - some based on unrealistic prototypes and others on mathematical analyses substantiated as far as practical with laboratory experimentation. However, progress made has been mainly not the result of any mathematical or physical definition of the process, but industry's willingness to spend more for larger and higher rate treatments. Service companies have met the demands of the industry for treatments of greater magnitude until in some areas, treatments of from 100,000 to 200,000 gal injected at rates approaching 100 bbl/min are not only common but are performed with minimum difficulty.

The cost of such treatments is of necessity great, and it is imperative that the manpower, equipment and materials be as effectively utilized as is technically possible. The purpose of this paper is not to clarify the turbid waters of fracturing theory, but to present the tools which we had used to make the technique more effective. Some equating will be necessary; however, development and discussion of theories will be largely confined to that necessary to justify the method of analysis.

Basic Assumptions

The following assumptions have been allowed as a basic definition of conditions:The pressure required to maintain fracture parting can be determined with fair reliability from either theoretical or empirical methods.The pressure required to maintain fracture parting is independent of fluid injection rate.For any one plane of parting, the functional variation in surface injection pressure with injection rate is the result of increased or decreased friction drop in conductor pipe and perforations.Functional variation in bottom-hole casing injection pressure with rate is the result of friction drop through perforations and is generally assumed, depending on number of perforations open, to be negligible for most wells below 3,000 ft in which ball sealers are not employed.
Numerical Simulation of Combustion Tube Experiments and the Associated Kinetics of In-Situ Combustion Processes
Authors: Lin C. Y. , Chen W. H. , Lee S. T. , Culham W. E.
Published: December 2007

This paper presents the results of numerical simulation of dry, forward combustion tube experiments. The kinetic aspects of in-situ combustion processes also are discussed. The goals of the study are to investigate the fuel deposition mechanism and to identify the key parameters affecting the performance of in-situ combustion processes.

The thermal simulator developed at Gulf R&D Co. was used in the study. It was modified to include the capillary outlet effects for a more realistic description of the oil and water productions. The following experimental data were matched: cumulative water and oil productions, position of the combustion front as a function of time, fuel consumption, temperature as a function of time and position, and the pressure drop across the tube. History matches were performed for two crude oils with distinctly different physical properties (gravities of 26.5 and 13°API [0.896 and 0.979 g/cm3]). The agreements between experimental data and simulation results were excellent.

Results indicate that the component equilibrium K-values and the kinetics of cracking reactions are the most important parameters affecting the fuel deposition, and that the fuel deposition mechanism, the fuel composition, and the locations and sizes of the transient zones depend on the crude oil and reservoir rock properties. Simulation results are always sensitive to the K-values of the light oil component but insensitive to the K-values of the heavy oil component. Results are sensitive to the kinetics of cracking reaction only if the cracking reaction is catalytic or the peak temperature and the fuel consumption are sufficiently high. Furthermore, the fuel available may or may not be solely in the form of coke.

Our study suggests that further investigations of the catalytic effect of reservoir rocks and reaction kinetics of the cracking reaction are needed. Also, more than two crude oil components may be required to simulate the evaporation effect of crude oil accurately.
Interpretation of Pressure-Composition Phase Diagrams for CO2/Crude-Oil Systems
Authors: Orr F. M. , Jensen C. M.
Published: December 2007

Results of single-contact phase behavior studies for CO2/crude-oil mixtures often are presented as pressurecomposition (P-X) phase diagrams. In such diagrams, regions of pressure and CO2 mole fraction for which more than one phase forms can be identified easily. Phase diagrams for CO2/crude-oil systems can be quite complex, however, since under some conditions such mixtures can form a liquid and a vapor, two liquid phases, or two liquids and a vapor in equilibrium. This paper examines P-X diagrams for two ternary systems, CO2/propane/hexadecane and CO2 /methane/hex- adecane, and describes transitions from one diagram to another that occur with changes in system temperature or changes in oil composition.

Nine experimentally determined P-X diagrams are presented for mixtures of Wasson crude oil with CO2. Three different oils, stock-tank oil, stock-tank oil plus 312 scf/bbl [560 std m3/m3] solution gas, and stocktank oil plus 602 scf/bbl [1084 std m3/m3] solution gas, were studied at three temperatures, 90, 105, and 120°F [32, 41, and 49°C]. Comparison of the resulting phase diagrams with those discussed for the simpler ternary systems indicates that the principal features of the crude oil phase diagrams are qualitatively consistent with those of the ternary systems. The results of the CO2/crude-oil experiments indicate that for low-temperature systems (below about 120°F [49°C]), the extrapolated vapor pressure (EVP) of CO2 is a good estimate of the pressure required to produce a dense, relatively incompressible CO2-rich phase that can extract hydrocarbons efficiently from a crude oil. Hence, in the absence of other experimental evidence, the EVP curve can be used as a rough estimate of the minimum miscibility pressure (MMP) for low-temperature reservoirs.
Effect of Flow Time Duration on Buildup Pattern for Reservoirs With Heterogeneous Properties
Authors: Streltsova Tatiana D. , McKinley Richard M.
Published: December 2007

For a heterogeneous reservoir, the shape of a buildup curve is strongly dependent on the length of the preceding flow period. Therefore, in exploration well testing, where the flow period is usually short, modification of the pressure buildup pattern caused by insufficient flow time can lead to erroneous interpretation of well behavior. Buildup pattern, as a function of flow time, is discussed here for various types of ideal heterogeneities such as linear reservoir discontinuities, natural fractures, vertical stratification, pressure support, and lateral permeability loss. A relationship is provided for the dimensionless flow time required to produce a certain buildup pattern. The effect of flow time on quantitative assessment of reservoir parameters is determined as well.
Effects of External Boundaries on the Recognition of Reservoir Pinchout Boundaries by Pressure Transient Analysis
Authors: Gerard Matthew G. , Horne Roland N.
Published: December 2007

Previous workers have shown that a semi-infinite reservoir with a pinchout boundary is characterized by spherical flow at long time. As a result, the presence of a pinchout should be recognizable from pressure-drawdown data by the appearance of a straight line on a graph of pressure vs. reciprocal square root of time. However, external boundaries of the system may be felt before spherical flow is established. This problem was studied by creating boundaries in the semi-infinite reservoir, using infinite-array superposition of the pinchout source function. Three partially closed systems were produced: (1) two parallel, vertical boundaries normal to the pinchout, (2) a vertical boundary opposite the pinchout, and (3) a second pinchout opposite the first. Values of pressure vs. time have been calculated for each of these cases.

It was found that the characteristic straight line begins at a time tD/dD2=5. This line would appear only if the external boundaries in the direction orthogonal to the pinchout were more than five times as distant from the well as the pinchout, and if boundaries in the direction parallel to the pinchout were more than eight times as distant.