bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effect of Microscopic Heterogeneity on CO2-Foam Mobility: Part 1--Mechanistic Study
Authors: Huh D.G. , Cochrane T.D. , Kovarik F.S. 
Published: December 2007

Summary
The mixing and flow behavior of a CO2/surfactant-solution/oil system in porous media depends on the pore structure. Two-dimensional (2D) flow-visualization experiments in several glass micromodels, each with a different length scale of heterogeneity, were performed at reservoir conditions. The mechanisms associated with gas permeability reduction were investigated in terms of microscopic heterogeneity, presence of oil phase, surfactant concentration, and flow rate in secondary and tertiary miscible CO2 floods. Results showed that foam can be generated by upstream and downstream snapoff. Fluid diversion was obtained not only by lamellae and foam, but also by multiple interfaces of CO2, surfactant solution, and oil. depending on the pore structure of the micromodel. The most important factors in the in-situ generation of foam, however, were the mixing of fluids and the aspect ratio of the pore structure.

Introduction
CO2 field projects have frequently experienced early gas breakthrough, and production will stop when an uneconomically high CO2/oil ratio is attained. Both high-pressure gas-foams and chemical gels are currently being considered for use as high-permeability-zone blocking agents--i.e., in profile modification--in many on-going CO2 flooding operations. This paper presents our preliminary investigation into the mechanisms responsible for CO2 fluid diversion, increased CO2 sweep efficiency, and the mobilization of bypassed oil when using high-pressure CO2-foam as a blocking agent. The capillary-tube model was used in one of the first attempts to study the generation and propagation Of a single lamella or bubble. Fried reported that in his glass-tube model, larger foam bubbles subdivided into smaller bubbles as they passed through pore constrictions. At the same time, some of the oil in the region invaded by the foam became emulsified, and the newly formed oil particles soon became immobile. He reported that this foam subdivision and emulsification could have been responsible for the resulting flow blockage.
JPT
P. 872^
Wettability: Fundamentals and Surface Forces
Authors: Hirasakl G. J. 
Published: December 2007

Summary
The wetting of mineral surfaces by water and oil is described by models of surface forces that become important when two surfaces approach each other. Force components are electrostatic, van der Waals, and structural. The electrostatic force depends on brine pH and salinity, crude oil composition, and the mineral. The surface forces are expressed as a disjoining pressure isotherm, and its integral is the specific interaction potential isotherm. The specific interaction potential isotherm can be used to determine the stable and metastable film-thickness profiles at the three-phase contact region for a given capillary pressure and/or curvature of the substrate. This profile gives the contact angle.
An Analytical Solution for Wellbore Heat Transmission in Layered Formations
Authors: Wu Yu-Shu , Pruess Karsten 
Published: December 2007

Summary
This paper presents a new analytical solution for wellbore heat transmission. Previous treatments of the wellbore heat-transfer problem are improved in several aspects: (1) nonhomogeneous formations are approximated as layered formations with different physical properties; (2) closed-form analytical solutions are obtained in both real and Laplace space; and (3) a more accurate formula is provided for the transient heat-conduction function, f(tD).
Pressure-Drawdown Test Analysis of a Gas Well—Application of New Correlations
Authors: Fligelman H. , Cinco-Ley H. , Ramey H. J. , Braester C. , Couri F. 
Published: December 2007

Summary
A new method of drawdown-pressure test analysis is proposed that takes into consideration the non-Darcian flow as well as the skin and borehole-storage effects. Two new correlations obtained from numerically simulated drawdown tests are used and the method of application is illustrated. The drawdown-pressure results of a synthetic numerically simulated test are used to recalculate the a priori known reservoir skin and permeability. A comparison between the obtained and the "true" reservoir skin and permeability shows an excellent agreement when the proposed method is applied.
Drawdown-pressure analysis of the given examples with the conventional method shows errors &gt; 5 % in the calculated permeability and &gt; 50% in the calculated skin factor.
Optimizing Well Spacing and Hydraulic-Fracture Design for Economic Recovery of Coalbed Methane
Authors: Zuber Michael D. , Kuuskraa Velio A. , Sawyer Walter K. 
Published: December 2007

Summary
Conventionally, proper well spacing and stimulation govern the economic attractiveness of producing natural gas from coalbeds. To provide an analytical foundation for this empirical evidence, reservoir simulation and economic analyses were conducted to gain insights into the optimum well spacing and hydraulic-fracturing treatments in typical "good" and "poor" geologic settings of the Oak Grove field in Alabama. We studied the economic benefit of gel-based fracturing treatments, the optimal well spacing for higher- and lower-permeability settings, and how to establish proper values for permeability and achievable hydraulic-fracture dimensions for optimal well spacing.
Results of a Field Test to Determine the Type and Orientation of a Hydraulically Induced Formation Fracture
Authors: Fraser C.D. , Pettitt B.E. 
Published: December 2007

Abstract
The planning phase of a program for expanding a shallow waterflood project was stalemated by lack of knowledge concerning the type and orientation of hydraulically induced formation fractures. Profitable development of the project is known to depend on successful fracture stimulation. To obtain in situ data about the induced fractures, a simple, downhole, impression sensing test was devised using an inflatable formation packer as the basic investigating element. A new well was hydraulically fractured, after which the formation packer, equipped with an especially sensitive rubber cover, was set in the pay interval. A perfect impression of the previously induced fracture was retained on the packer element. This impression showed that the fracture was vertical, oriented north 730 east, and present along the entire 9-ft section of impression rubber. Prior to the down-hole test, fracture orientation and type had been predicted based on published theories describing the relationship between tectonic stresses and artificial formation fracturing. The test data verify these predictions. As a sidelight, it is concluded that deep notches in the pay sand do not cause horizontal fractures in this area.

Introduction
The technical literature of recent years contains many papers which attempt to provide insight concerning the type, orientation and fluid- carrying ability of hydraulic fractures. Theoretical methods have been proposed with which the field engineer can make optimum use of artificial formation fracturing as a stimulation technique. The purpose of this paper is to describe an attempt to corroborate theoretical concepts so that combination waterflood-fracture stimulation program could he exploited to maximum advantage. The area involved is that bounded by Mobil Oil Co.'s Chalk Waterflood project which is located in the Howard Glasscock field of eastern Howard County, Tex. Production is from the 1,600-ft Queen sand of Permian age. This sand possesses an average porosity of 23 per cent, an average permeability of 57 md, an average water saturation of 35 per cent and an average gross thickness of 25 ft. The sand is very fine-grained and contains considerable amounts of gypsum, silt and clay. Geologically, the project is situated on the Eastern Platform of the Midland basin. Fig. 1 is a map showing the project area. The Chalk flood has been in operation since 1947; however, results were generally discouraging.
JPT
P. 463^
An Experimental Test of the Cutting and Rejoining Model for Representing Porous Bodies
Authors: Hancox N.L. 
Published: December 2007

Abstract
Previous researchers have used the cutting and rejoining model to represent a porous body when attempting to place Archie's law on a theoretical basis and calculate rock permeabilities (F = phi m, where F = formation factor, phi = porosity and m = a constant). In using the model, a porous solid is assumed to consist of sections with parallel sides containing straight, continuous pores of total porosity phi (pore to total volume or, for a homogeneous body, pore to total area). The joining of pores at an interface between two sections is assumed to be random which results in a common pore area phi. This reduced area phi is then taken as that area which limits electrical conduction or fluid flow in the body. Agreement between experimental results and results calculated using a model is not always good. Because of this, various modifications of the model are presented for instance, the random nature of the joining is questioned. Formation factor measurements on specially constructed porous specimens are described in this paper. It is concluded that the common pore area limits flow completely only if sections containing straight pores are very thin, and that, in most natural materials, the common pore area at an interface must be greater than that given by random joining. However, the model is still useful in permeability calculations, provided that the fractional area limiting flow is determined from formation factor measurements.

Introduction
Two important properties of porous media are permeability k, which describes the ease with which a fluid can flow through a porous medium, and formation factor F, defined as the ratio of the resistivity of a saturated specimen to the resistivity of the saturating liquid which describes the electrical properties of the saturated material. k is defined by Darcy's law,
(1)
where mu = liquid viscosity, q = flow rate, L = length of specimen, p = pressure across the specimen and Ae = the effective area over which flow occurs. F is given experimentally by Archie's law,(2)
where phi is porosity defined as the pore to total volume or, for a homogeneous body, the pore to total area; and m lies between 1.3 for loose sand and 2 for cemented sand. Consider a porous body of total cross-sectional area A and length L, saturated with a liquid of resistivity R and with an effective area for conduction of Ae. Then, from the definition of F given previously,
(3)
or, from Eqs. 2 and 3,
(4)
Thus, in any attempt to calculate k or F, some assumptions must be made concerning the pore structure of the body and a value derived for Ae.
To determine Ae, Childs and George and Wyllie and Gardner suggested an elementary statistical representation often referred to as the cutting and rejoining model of a porous body. The body is assumed to be composed of two or more parallel-sided sections of porosity phi, containing straight, continuous pores with a common pore area of phi at an interface between two sections. The value is given by a random joining of the pores in either section.
Deep-Set Subsurface Safety Valve Actuated by Jet-Pump Differential Pressure
Authors: Barnes John A. , Snlder Phil M. , Swafford Chuck V. 
Published: December 2007

Summary
Offshore oil and gas production often requires placement of a subsurface safety valve (SSSV) in the tubing string to prevent uncontrolled flow from the well. In many wells, this requirement can preclude maximizing production through the use of high-capacity artificial-lift techniques, such as jet pumping. An innovative approach was developed and field-tested in the McArthur River field, Cook Inlet, AK, to overcome problems associated with incorporating SSSV's in jet-pump completions. This method provides surface control over the valve and does not restrict production rate. In this approach, an SSSSV was placed in the tubing string below a jet pump at 9, 800-ft [3000-m] true vertical depth (TVD) to satisfy safety requirements. The system design allows the SSSV to be controlled from the surface with no dependence on hydraulic control lines to surface. The system was later improved to allow the SSSV to be reverse-circulated from the well for repairs or remedial activities.
Marketing and Distribution of Helium
Authors: Troast David W. 
Published: December 2007

Abstract
Recently there have been many changes in the marketing and distribution of helium, one of the most versatile of industrial gases. New uses, equipment and systems, as well as a greater role for private enterprise, have been important factors in creating an annual $45 million market of 1 billion cu ft.

Introduction
Helium is a combination of unusual properties and characteristics that make it useful in a wide variety of applications. Notable for its extreme lightness, helium is nearly 10 times lighter than argon and about seven times lighter than air. The helium molecule is small and readily diffuses through even the smallest of openings. Helium is a good conductor of heat and sound. Other properties and characteristics include inertness, low solubility, low index of refraction, resistance to nuclear radiation and the lowest normal boiling point of all gases (Table 1).
While the product and its major sources have remained essentially the same for years, nearly everything else connected with helium has undergone recent changes.

Growth of Private Production and Distribution
A significant change in the helium industry has been development of a greater role for private enterprise in helium production and distribution. In cooperation with the Helium Activity of the U. S. Bureau of Mines, private enterprise now is engaged in producing crude helium for USBM's conservation storage program, as well as in producing pure liquid and gaseous helium for commercial sales. Private efforts also have created a new nationwide system for the distribution of large quantities of liquid helium.

Helium Demand Grows Rapidly
The over-all market for helium is growing steadily at a rate of about 15 percent annually, which is faster than the market for most gases and about on a par with nitrogen. Several factors provide the impetus for this growth. Helium is often the best and sometimes the only substance to fulfill requirements for many important applications associated with advanced technology and major governmental or commercial ventures. The most spectacular application, and the one most subject to fluctuation in the future, is the growth of the rocket and missile field that prompted creation of many new applications for helium in both federal programs and private industry.
Most advanced research and development work conducted by institutions and private industry in a wide variety of fields has some requirement for helium as a gas or liquid. One of the fastest growing areas is cryogenic research requiring liquid helium for low-temperature studies. Successful results of research and development in the past few years have created many new products and processes requiring helium.
Pressure-Transient Analysis for Horizontal Wells
Authors: Kuchuk Fikri J. , Goode Peter A. , Brice Bradley W. , Sherrard David W. , Thambynayagam R.K. Michael 
Published: December 2007

Summary
In recent years, pressure-transient behavior of horizontalpressure-transient behavior of horizontal wells has received considerableattention because of the increase in horizontal drilling. This paper presentsan interpretation method for presents an interpretation method forhorizontal-well pressure-transient testing that is applied to a buildup testfrom a horizontal well in the Prudhoe Bay field. The complex flow Prudhoe Bayfield. The complex flow geometry associated with horizontal wells makeswell-test interpretation difficult. Unique determination of the systemparameters from pressure data with a short testing time (typical test times forvertical wells) and/or production time is not possible. We production time isnot possible. We must run drawdown and buildup tests and acquire the downholeflow rate with pressure to estimate the reservoir parameters accurately.

Introduction
Interpretation of well tests from horizontal wells is much more difficultthan interpretation of those from vertical wells because of a considerablewellbore storage effect, the 3D nature of the flow geometry and lack of radialsymmetry, and strong correlations between certain parameters. Also, zonalvariations of vertical permeability and shale distribution complicateinterpretation.
A well-defined flow period, comparable to that of the infinite-acting radialflow period (free from storage and boundary effects) period (free from storageand boundary effects) of a vertical well, is not apparent for horizontal wells, largely because most horizontal wells exhibit partial penetration effects evenwhen they are hilly perforated. Specific methods have been perforated. Specificmethods have been proposed to identify flow regimes and their proposed toidentify flow regimes and their durations under ideal conditions. AlthoughReiss and Sherrard et al. presented performance and production data fromperformance and production data from several horizontal wells and mentionedinterpretation of well-test data, they did not show how to extend theidentification and usage of flow regimes to the interpretation of realpressure-transient tests.
This paper presents a method for the interpretation of wells data fromhorizontal wells and analyses of pseudosynthetic and real well-test data.

Solutions With and Without Gas Cap or Aquifer
In a horizontal well, there is usually considerable wellbore volume (50 to100 bbl) below the measurement point, even if the downhole flow rate ismeasured or a downhole shut-in device is used. The storage effect with thisadditional volume typically lasts longer than that in a vertical well in thesame formation because the anisotropy reduces the effective permeability atearly times to root of kHkV.
The Thermosludge Water Treating and Steam Generation Process
Authors: Hull R.J. 
Published: December 2007

Abstract
The Thermosludge process internally softens and makes high-pressure steam directly from hard and saline oilfield or other water. Pilot plant and early full-scale plant work established several physical and chemical principles found necessary or desirable for good operation, and for control and practical elimination of scale on the process heating surfaces. These principles are use of a secondary liquid heat transfer medium, provision of time and space for water chemical reactions ahead of the boiling zone, and presence of sludged reaction products throughout the boiling zone. Other pertinent factors are discussed such as dissolved and suspended solids limits, foaming, corrosion, and heat transfer.

Introduction
In 1964 considerable use of steam in California oil fields was beginning to cause shortages of good steam generator feedwater in some areas. It seemed evident that in some situations oilfield brine or other low-quality water would have to be used to generate high-pressure steam directly. The Thermosludge process was developed to meet this need, and early results of its field use have been reported previously. This article discusses both pilot plant and full-scale plant design and operation particularly relative to the high-temperature reactions and scaling characteristics of some of the chemicals present in the waters.
Present understanding of the process should allow broader use in its original field, and in other processing areas dealing with difficult waters.

Pilot Plant Design and Operation
After considerable study of chemical and engineering factors involved, a pilot plant program was set up. Three main theories or principles believed to lead to successful operation were followed in the pilot plant design and the same principles were carried into the full-scale plant design.
First, heat should be applied via a secondary fluid heat transfer medium rather than directly in a combustion space. Relative to direct-fired beating, the secondary fluid heating guarantees that maximum tube wall temperature will be well within the allowable metal temperature limit regardless of local scaling or salting up. Many situations call for soluble salt in the steam generator in concentrations of as much as 15 percent by weight perhaps half of the limiting solubility. Even if conventional tube scaling were somehow entirely prevented, such situations would require the inherent heat flux control of a secondary heat medium to prevent gross fouling and plugging by salt deposits.
Second, means should be provided in terms of high-temperature time and volume to preheat and chemically react the feedwater before it enters the boiling zone. The practicality of this is based on the expectation that thermally induced mineral sludging reactions will proceed much faster and more completely in the 350 to 600F environment than, for example, in the conventional lime-soda process. Thus, the feedwater should be entirely softened by the time it arrives at the boiling zone.
Measuring Low Flows in Devonian Shale Gas Wells With a Tracer-Gas Flowmeter
Authors: Bennett Richmond , Schettler Paul D. , Gustafson Todd D. , Gillette Illona E. 
Published: December 2007

Summary
A novel design for a downhole flowmeter that can locate and quantify gas-entry points in a well is presented. The instrument has a gas-tracer injector at its lower end and a tracer detector at its upper end. We determine gas flow in the well by injecting tracer gas at a precisely measured rate into the natural gas flow and measuring the concentration with the detector. The result is a wireline log that locates and quantifies natural gas sources from the decrease in measured flow as the wireline instrument passes each source. The new design has been tested against calibrated gas flows in the laboratory and in Devonian shale gas wells in the field. The new flowmeter is compared with spinner, temperature, sonic, and television logs. The instrument provides an expanded flow range compared with spinner logs and furnishes quantitative mass-flow information compared with incomplete and qualitative indications provided by temperature and sonic logs.
Tubing and Casing Buckling in Horizontal Wells (includes associated papers 21257 and 21308 )
Authors: Chen Yu-Che , Lin Yu-Hsu , Cheatham John B. 
Published: December 2007

Summary.
This paper describes new theoretical results for predicting the buckling behavior of pipe in horizontal holes. Pipe buckling in horizontal holes occurs initially in a sinusoidal mode along the low side of the hole; at higher axial compression a helix is formed. Equations are given for computing the forces required to initiate these different buckling modes. Simple experimental laboratory results confirm the theory. Results presented in this paper apply to friction modeling of buckled tubulars to help predict when pipe can be forced to move along a long section of a horizontal well.

Introduction
Since 1950, many analyses have been performed on the mechanics of pipe in oil and gas wells. Lubinski et al. defined the helical buckling behavior of pipes in vertical wells. However, the postbuckling behavior of pipe in horizontal wells is different from that in nearly vertical wells. Knowledge of the configuration of buckled tubulars is important to prevent costly failures and to predict whether a tool can be forced along a horizontal well. This paper provides methods to analyze these problems. Two modes of buckling can occur for tubulars in horizontal or steeply inclined wells: helical and sinusoidal (Fig. 1). The axial compressive force required to buckle the pipe into a sinusoidal configuration depends on pipe stiffness and weight and on hole size in a manner similar to a beam on an elastic foundation. As axial force is increased, the buckling mode changes from sinusoidal to helical. Model experiments confirm the results of the analyses.