bluuebunny/crossref_metadata_2025_split huggingface dataset:
Completing High Pressure Gas Wells - Mechanics and Problems
Authors: Kilsdonk R.A. 
Published: December 2007

Introduction
This discussion is limited to high pressure gas wells or wells with abnormal pressure gradients. It does not cover extreme high pressure gas wells such as have been recently completed on the Gulf Coast where shut-in tubing pressures have been recorded in the vicinity of 12,000 psi. It is realized that such wells would probably be of more singular interest; however, since relatively few have been completed to date, the data are very meager. It is the purpose of this paper to review some of the mechanics and problems involved in the completion of high pressure gas wells.
Generally speaking, completion practice refers to operations which take place from the time the well is drilled through the productive zones and continues until the well is placed on production.
The wells which will be discussed might be termed as medium high pressure gas wells having pressure gradients of about 0.8 psi/ft of depth. Three gas wells in this category were recently completed in the Gulf of Mexico approximately three miles off the Texas coast near Mustang Island. The completion of these wells will be discussed in detail.

Casing Program
The proper design of casing programs for high pressure gas wells is of utmost importance. This is particularly true of offshore wells where the safety of personnel and equipment is at stake. For this reason the factors of safety must be maintained well within the accepted limits. The program for all three offshore wells followed the same general pattern except for the 5-in. OD oil string. Due to trouble encountered with sticking in the deviated hole, the oil string was swaged to 4.5-in. OD at the bottom of the 7-in. OD casing at approximately 10,600 ft.
The typical program is shown in Table 1. Total average weight of tubular goods used in each well was 1,257,000 lb or approximately 628 tons. For the sake of simplicity the details of completion of Well No. A–3 will be discussed since all three wells were completed in the same manner.
Sand-Consolidation Resins—Their Stability in Hot Brine
Authors: Rensvold Roger F. 
Published: December 2007

Abstract
Four commercial in-situ sand-consolidation resin systems and one resin-sandpack system were tested for durability in hot [160°F (71.1°C)] flowing brine for up to 28 months, and in as much as 30 million PV brine. Brine was selected as the test fluid since it is considered to be more damaging than oil to the stability of resin-consolidated sand.
Two epoxy and two furan systems were investigated. Other commercial consolidation techniques—e.g., involving phenol formaldehyde and phenolic furan resins described in the literature1—have been recognized as effective sand-stabilization products; however, some limitations had to be placed on the scope of the study because of equipment and time limitations. Perhaps these techniques will be the subject of future investigations. Note that all processes evaluated in this investigation used silane coupling agents contained in the resinous materials. These agents increase the stability of sands consolidated by organic polymers.2
The overflush-catalyzed furan resin (System A) and the internally catalyzed epoxy resin (System D) demonstrated greater stability under the specific test conditions employed. System A retained higher strength during the first 15 million PV. Thereafter, System D appeared to be better. System A exhibited the highest initial permeability, and, after 5 million PV, Systems A, B, and D were about equal in permeability. From that point, the permeability of System A slowly increased, while decreasing for Systems B and D.
The epoxy-resin sandpack (40- to 60-mesh sand) showed little change in compressive strength after exposure to more than 30 million PV of hot, flowing brine.
High Pressure Cycling with Hydrogen Sulfide Laden Gas
Authors: Miller C.O. 
Published: December 2007

Introduction
This paper describes the use of hydrogen sulfide laden gas in high pressure cycling in the New Hope, Smackover field located in Franklin County, Tex., some 50 miles north of Tyler. In Dec., 1953, Tidewater Oil Co. and Seaboard Oil Co. discovered the New Hope, Smackover field, underlying in part the New Hope oil field also discovered by these two companies in 1943.
The New Hope, Smackover gas-condensate reservoir was discovered by completion of the T. J. Ramey Unit 1–1-D well with open hole 12,086 to 12,322 ft. On test the well yield was approximately 150 bbl of "sour" condensate per million cubic feet of sour or hydrogen sulfide laden gas. This reservoir was discovered by deeper drilling on a known structure. Discovery well location was made on the basis of deep geophysical reflections.
Engineers have recently recognized that the so-called gas-condensate reservoir products actually exist in the formation in the gas phase. The condensate, as its name implies, is a portion of the liquefiable hydrocarbons whose recovery is accomplished by cooling or reducing the reservoir fluid pressure to a point within the retrograde condensate range.
One of the first questions to arise when a new gas-condensate reservoir is discovered is, What are the reserves? Other questions of equal importance arise. What plan of production shall be employed? Shall it be pressure depletion? Cycling? Or a combination of both? Certain economic and physical factors may alter an original plan of production during the actual producing period of a reservoir. It is probably safe to say all gas-condensate field production methods need to be constantly observed and periodically studied in detail to assure optimum production.
Rheology Enhancement by Molecular Association Complexes
Authors: Prud'homme Robert K. , Uhl Jonathan T. 
Published: December 2007

Abstract
Associations between polyethylene oxide polymer (PEO) chains and species containing sulfate groups can be used to increase the viscosity and elasticity of polymer solutions. The condensation of sodium dodecyl sulfate (SDS) micelles onto the PEO chain is shown to lead first to chain coil collapse and then to network or gel structure formation as SDS concentration is increased. Stronger interactions are produced between PEO and either Congo-red dye (a large organic molecule with two widely spaced sulfate groups) or polystyrene sulfonate (PSS). In these cases the association complexes lead to minor changes in the solution viscosity but large changes in the primary normal stress and storage modulus G′ at low frequencies. The structures formed by association are disrupted by flow but rapidly re-form. Association complexes are an attractive way of obtaining high-viscosity fluids that would be resistant to permanent shear degradation.
The Rules for Achieving High Solubilization of Brine and Oil by Amphiphilic Molecules
Authors: Bourrel M. , Chambu C. 
Published: December 2007

AbstractThe oil-recovery effectiveness of a chemical flood has been proved related to the phase behavior of the brine/oil/surfactant system. In particular, it is advantageous to formulate the system so that optimal three-phase behavior is obtained. However, it also has been demonstrated that all the optimized systems are not equivalent in terms of solubilization, interfacial tensions (IFT's), and oil-recovery efficiency.This paper addresses the conditions that promote high solubilization in microemulsions, a property correlated to the values of the IFT and therefore correlated to the ability of such systems to displace the oil in porous media. When one formulation parameter is changed, another parameter must be varied at the same time for compensation to reoptimize the system. The mechanism of solubilization is investigated experimentally by considering the usual formulation parameters: salinity, oil type, alcohol type and concentration, and surfactant structure and type (anionics and nonionics). The results are interpreted in terms of interaction energies between surfactant, oil, and water. In particular, the role of the alcohol and its impact on the solubilization by amphiphilic systems are discussed in detail and interpreted.Moreover, the concepts developed in this paper explain the effect of the surfactant structure and therefore aid in the design of amphiphilic molecules exhibiting a high solubilizing power for given conditions of brine, temperature, etc.
The Effect of Live Crude on Phase Behavior and Oil-Recovery Efficiency of Surfactant Flooding Systems
Authors: Nelson Richard C. 
Published: December 2007

AbstractNeither pressure alone nor pressurizing with methane affects phase behavior of a particular surfactant/brine/stock-tank-oil system. Oil-recovery efficiency in corefloods is not significantly different whether the stock-tank oil is pressurized with methane or diluted with iso-octane to the viscosity of the live crude. In contrast, phase behavior and oil-recovery efficiency do change upon methane pressurization when a lower-molar-volume synthetic oil is substituted for the stock-tank oil. Some thermodynamic insight regarding the different behavior of the two oils is offered.
A Three-Parameter Representation of Surfactant/Oil/Brine Interaction
Authors: Puerto Maura C. , Reed Ronald L. 
Published: December 2007

Abstract
When optimal salinity, Cϕ, and solubilization parameter Vo/Vs are augmented by oil molar volume, Vmo, the resulting three-parameter representation provides a more precise description of microemulsion phase behavior than has previously been available. It then becomes possible to introduce the idea of equivalent oils (Eqo's) as a replacement for the equivalent alkane carbon number (EACN), which is shown to lack some of the properties needed to implement efficient preliminary screening of microemulsions for EOR.
Broadly speaking, oils are "equivalent" when they have the same molar volumes, optimal salinities, and solubilization parameters. If, in addition to equivalence, oils are required to have equal viscosities and similar phase behavior as a function of surfactant concentration, then it may be possible to replace microemulsion floods of live crude at high pressure with floods of appropriately diluted dead crude at low pressure.
This paper places EACN in perspective by means of the three-parameter representation, explores parallel effects of temperature and alcohol cosolvents, and reveals essential nonlinearities in optimal salinity as a function of oil composition (and hence molar volume) for mixtures of various oils. Much of this is subsequently used to develop methods for preparation of Eqo's and the more complex but evidently essential equivalent systems (EqS's) needed to model live crudes.
Magnitude and Detailed Structure of Residual Oil Saturation
Authors: Chatzis Ioannis , Morrow Norman R. , Lim Hau T. 
Published: December 2007

Abstract
Experimental results are presented that demonstrate the effect on residual oil, under water-wet conditions, of particle size, particle-size distribution, macroscopic and microscopic heterogeneities, microscopic dimensions such as ratio of pore-body to pore-throat size, and pore-to-pore coordination number. Experiments were performed in random packs of equal spheres, heterogeneous packs of spheres with microscopic and macroscopic heterogeneities, two-dimensional (2D) capillary networks having various pore geometries, and Berea sandstone. Detailed information on residual oil structure is presented, including blob-size distributions of residual oil. Major conclusions are (1) residual saturations are independent of absolute pore size, per se, in systems of similar pore geometry; (2) well-mixed two-component aggregates of spheres gave virtually the same residual saturations as random packings of equal spheres; (3) clusters of large pores accessible through small pores will retain oil; (4) high aspect ratios tend to cause entrapment of oil as a large number of relatively small blobs, each held in single pores; and (5) the role of pore-to-pore coordination number is generally secondary; hence, correlations that have been proposed between residual oil and coordination number are unreliable.
Heat Losses During Flow of Steam Down a Wellbore
Authors: Satter Abdus 
Published: December 2007

Abstract
Studies of wellbore, heat transmission during the injection of a hot fluid, as either gas or liquid, have appeared in the literature. The present investigation takes into account the effect of condensation, which is of practical significance when considering steam injection operations. Calculation procedures are given for superheated and for saturated and undersaturated steam. Effects of injection rate, time, pressure, temperature and depth of a well on heat losses have been analyzed. The benefits of using a packer are discussed. Also presented are correlations for estimating heat losses involved during injection of saturated steam.

Introduction
Studies of wellbore heat losses during the injection of a hot fluid have appeared in the literature. Ramey has presented a useful solution for calculating temperature of a heated gas as a function of depth and injection time. Ramey and others have also presented solutions for the hot liquid case. No method is available to take into account the effect of condensation, which is of practical significance when considering steam injection operations. This paper presents a method of estimating the quality of a condensing fluid as a function of depth and time. The approach is basically the same as that used by Ramey. The following injected fluids and conditions are considered in this study:Injection of superheated steamA. Decrease in temperature until cooled to thesaturated stateB. Condensation until condensed completely into hot(saturated) waterInjection of saturated or undersaturated steam;condensation until condensed completely into hot(saturated) water. Although this investigation does not include cooling of water after steam is completely condensed, Ramey's solution for the hot liquid case can be used for this purpose.
The effects of various process variables on heat losses during the injection of steam into a well are investigated.

THEORY QUALITY OF CONDENSING STEAM
Predicting the behavior of condensing steam flowing down the injection wellbore requires an estimate of the quality of steam, i.e., the mass fraction of vapor in the mixture. Let us divide the total depth of the injection well into several segments which might be, but do not have to be, of equal magnitude. Consider condensation within a given depth interval AZ, the bottom of which is located at a depth Z from the surface (Fig 1). The following equation, derived in the Appendix, relates the quality of steam at the bottom of an interval to that at the top of the interval:
(1)
(2)
(3)
See the nomenclature for symbol definitions. The major assumptions made in the solution are is follows:Steam is injected at a constant rate, wellheadpressure, temperature and quality.A down-hole packer is used to prevent steam from entering the tubing-casing annulus. The annulus is assumed to be filled with air at low pressure.
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P. 845ˆ
Elimination of Xanthan Microgels by New Enzymatic Treatments
Authors: Kohler Norbert , Milas Michel , Rinaudo Marguerite 
Published: December 2007

Abstract
Polysaccharase and particularly combined polysac-charase/protease treatments offer new alternatives for clarifying aqueous xanthan gum dispersions. Each enzyme has its specific action—the proteases on the insoluble residual bacterial cells, and the polysaccharases primarily on the microgels.
Preliminary tests of these enzymatic treatments for scheduled field applications show promising improvements in filterability, especially for solutions prepared from xanthan powders.
Flooding of Semi-Depleted Solution Gas Reservoir in Fullerton Field
Authors: Nolan W.E. , Williams R.M. 
Published: December 2007

Abstract
Little flooding experience or technology exist which are applicable to solution gas-drive reservoirs which have been depleted considerably below the bubble point. The Fullerton field pilot is an example of flooding under these conditions where an intermediate stage or depletion exists and the water flooding will be neither a pressure maintenance project nor a depletion flood. In the case of Fullerton field where the gas saturation is approximately 18.0 per cent of total pore volume, "fill-up" will not be reached for a number of years after flooding operations begin. During this period compressibility of fluids and relative permeability factors determine performance of producing wells. The non-steady-state performance which will be in effect for a considerable time cannot be directly predicted by any presently accepted theoretical means.
The pilot flood has yielded considerable information which can be used in predicting performance during this important stage of flooding. The pilot has shown that favorable reactions on producing wells adjacent to injection wells are in effect long before a theoretical fill-up is obtained. This does not indicate poor performance, but merely that the reservoir fluids are compressed to the point where a significant oil bank is formed. This isolated pilot pattern flood, where all offset wells are producing, gives some indication of what might be expected under both pattern and line-drive flooding. The pilot has progressed to a point where sufficient stock-tank oil has been recovered, in the area under pattern flooding, to justify full scale flooding. In the area surrounding the pattern flood no means exist for confining fluid movement, and performance is a function of the interdependent combination of relative permeability, fluid saturation and fluid compressibility. This pilot flood has shown the degree to which outside offset producing wells respond prior to reaching gas-space fill-up and the degree to which productivity is affected by changes in saturation accompanied by only relatively slight pressure increase. Producing wells inside the pattern flood have shown the degree to which productivity can be affected by saturation change and a considerable increase in bottom-hole pressure.
Study of the Oil Wedge Phenomenon Through the Use of a Chemical Flood Simulator
Authors: Tham Min Jack , Nelson Richard C. , Hirasaki George J. 
Published: December 2007

Abstract
The presence of an oil wedge in some coreflood experiments indicates possible inefficient use of expensive surfactant mixture. The oil wedge problem his been studied in some detail by means of a chemical-flood simulator. Knowledge gained from this study will be useful in the design of future field-scale chemical floods.
The formation of an oil wedge in a chemical flood is caused by an unfavorable gravity override condition at the front of the surfactant bank and gravity underrun at the back side of the surfactant bank and by the limited availability of surfactant in the flood. Chemical-flooding systems that are Type III over a broad salinity range are less likely to form an oil wedge than systems that are Type III over a narrow salinity range.
The gravity override condition at the front of the surfactant bank may be improved by designing a chemical-flooding system that is Type III over a broad salinity range and that has a high upper Type III boundary on the salinity-requirement diagram. The gravity override condition can be improved also by preceding the chemical slug with a low-salinity preflood or by lowering the chemical-slug salinity.
The unfavorable gravity underrun condition at the back side of the surfactant bank can be improved by increasing the injection rate, by increasing the drive viscosity, by lowering the chemical-slug salinity, or by designing a better chemical-flooding system that has a broad Type III salinity range.
On-Site Acidizing Fluid Analysis Shows HCl and HF Contents Often Varied Substantially From Specified Amounts
Authors: Watkins David R. , Roberts Glen E. 
Published: December 2007

Summary
A quality-control survey of 162 acidizing fluids revealed the following problems. problems.Acid concentrations were often too high or too low.Frequently, fluids were not thoroughly mixed.In some cases, fluids contained incompatible additives.
A field test kit and conventional laboratory analyses were used to determine the acid and iron concentrations in fluids from 44 acid jobs in southern California over a 4-year period. Results of the survey suggest that analysis of acid concentrations would enhance the quality of acidizing programs. The kit described here permits the simple and rapid analysis programs. The kit described here permits the simple and rapid analysis that would contribute to a quality-control program.

Introduction
Acidizing fluids are the product of research and field experience. Although laboratory tests contribute to the design of acidizing fluids, field tests and experience determine the final fluid composition. Once a fluid appears to work, it will be used routinely in a specific field. Routine use, however, does not ensure good acid quality. These fluids are complex mixtures that contain several critically active chemicals. One fluid may contain HCl, HF, acetic acid, corrosion inhibitor, antisludging agent, foaming agent, solvent or mutual solvent, sequestering agent, and other chemicals. Each one contributes a specific function and must be compatible with the others. The presence of these additives in proper concentration is always critical.
Therefore, we initiated a quality-control program for acids used in southern California. Our objective is to obtain the fluids we specify bychecking acid quality on the job to prevent the use of poor-quality fluids,defining quality control problems so they can be solved, andgiving the acid suppliers more incentive to control the quality of their fluids.
This paper presents the results of a 4-year quality control survey and a description of the kit used to analyze the fluids.

Description of the Acid Quality Test Kit
The test kit (see Fig. 1) permits rapid analysis of HF, HCl, and iron concentrations. Plastic labware is used almost exclusively in the kit to avoid the inconvenience of breakage in the field and to avoid contact of HF with glass. The HCl and HF concentrations in weight percent are determined by titration. Samples are titrated by using constant-volume dispensing bottles rather than a buret. These bottles accurately and reproducibly dispense 1-mL (1-cm3) quantities of the titrating solution; therefore, the analytical result is a concentration range rather than a discrete concentration. This range spans 0.4% for HF and 0.91% for HCl in the absence of HF. For example, in the HF titration each milliliter of titrating solution represents 0.4% of HF. If six 1-mL (1-cm3 ) quantities of the solution are required to reach the endpoint, the HF concentration is known to be between 2.0 and 2.4%.
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p. 865
Laboratory Tests on Heavy Oil Recovery by Steam Injection
Authors: Closmann Philip J. , Seba Richard D. 
Published: December 2007

Abstract
This paper presents results of laboratory experiments conducted to determine the effect of various parameters on residual oil saturation from steamdrives of heavy-oil reservoirs. These experiments indicated that remaining oil saturation, both at steam breakthrough and after passage of several PV of steam, is a function of oil/water viscosity ratio at saturated steam conditions.