bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Non-Darcy Flow on the Constant-Pressure Production of Fractured Wells
Authors: Guppy K. H. , Cinco-Ley Heber , Ramey Henry J. 
Published: December 2007

Abstract
In many low-permeability gas reservoirs, producing a well at constant rate is very difficult or, in many cases, impossible. Constant-pressure production is much easier to attain and more realistic in practice. This is seen when production occurs into a constant-pressure separator or during the reservoir depletion phase, when the rate-decline period occurs. Geothermal reservoirs, which produce fluids that drive backpressure turbines, and open-well production both incorporate the constant-pressure behavior.
For finite-conductivity vertically fractured systems, solutions for the constant-pressure case have been presented in the literature. In many high-flow-rate wells, however, these solutions may not be useful since high velocities are attained in the fracture, which results in non-Darcy effects within the fracture.
In this study, the effects of non-Darcy flow within the fracture are investigated. Unlike the constant-rate case, it was found that the fracture conductivity does not have a constant apparent conductivity but rather an apparent conductivity that varies with time. Semianalytical solutions as well as graphical solutions in the form of type curves are presented to illustrate this effect.
An example is presented for analyzing rate data by using both solutions for Darcy and non-Darcy flow within the fracture. This example relies on good reservoir permeability from prefracture data to predict the non-Darcy effect accurately.
Vesicular Dispersion Delivery Systems and Surfactant Waterflooding
Authors: Puig Jorge E. , Franses Elias I. , Talmon Yeshayahu , Davis H. Ted , Miller Wilmer G. , Scriven L. E. 
Published: December 2007

Abstract
Surfactant waterflooding processes that rely on ultralow interfacial tensions suffer from surfactant retention by reservoir rock and from the need to avoid injectivity problems. New findings reported here open the possibility that by delivering the surfactant in vesicle form, more successful low-concentration, alcohol-free surfactant waterflooding processes can be designed.
Basic studies of low concentration (⩽2 wt%) aqueous dispersions of lamellar liquid crystals of a model surfactant, Texas No. 1, have established the role of dispersed liquid crystallites in the achievement of ultralow tensions between oil and water. Recent work, including fast-freeze, cold-stage transmission electron microscopy (TEM), reveals that sonication both in the absence and the presence of sodium chloride converts particulate dispersions of Texas No. 1 into dispersions of vesicles, which are spheroidal bilayers or multilayers less than 0.1 µm in diameter filled with aqueous phase. Vesicles ordinarily revert only very slowly to the bulk liquid crystalline state. We find, however, that their stability depends on their preparation and salinity history, and that contact with oil can accelerate greatly the reversion of a vesiculated dispersion and enable it to produce low tensions between oil and water.
Tests with Berea cores show that surfactant retention and attendant pressure buildup can be reduced greatly by sonicating Texas No. 1 dispersions to convert liquid crystallites to vesicles. In simple core-flooding experiments both the unsonicated liquid crystalline dispersions and the sonicated vesicle dispersions are able to produce substantial amounts of residual oil. We point out implications and directions for further investigation.
Polymer/Surfactant Transport in Micellar Flooding
Authors: Chiou C. S. , Kellerhals G. E. 
Published: December 2007

Abstract
For the surfactant formulations used (particular surfactant concentration, surfactant type, cosolvent type, cosolvent concentration, etc.), the results show that surfactant systems containing polymer as a mobility control agent may exhibit adverse polymer transport behavior during flow through porous media. Polymer generally lagged behind the surfactant even though the two species were injected simultaneously in the surfactant slug. This poor polymer transport definitely could have a detrimental effect on the efficiency of a micellar flooding process in the field. Phase studies show that when some surfactant systems containing xanthan gum are mixed with crude oil at various salinities, a polymer-rich, gel-like phase forms. The polymer lag phenomenon in core tests can be related to phase separation due to divalent cations generated in situ as a result of ion exchange with the clays and the surfactant.
Evaluation of Acid-Gelling Agents for Use in Well Stimulation
Authors: Crowe C. W. , Martin R. C. , Michaelis A. M. 
Published: December 2007

Abstract
Various polymers and other thickening agents have been evaluated as gelling agents for hydrochloric acid (HCl). These materials were compared on the basis of thickening efficiency, acid stability, and residue formation upon spending of the acid. Thickeners tested include xanthan polymers (XP), guar gum (GG), hydroxyethyl cellulose (HEC), carboxymethylhydroxyethyl cellulose (CMHEC), polyacrylamide (PAM), polyvinyl alcohol (PVA), polyvinylpyrrolidone (PVP), acrylamide/sodium-2-acryl-amido-2-methylpropane sulfonate copolymer (PAM/AMPS), and a cationic surfactant that thickens acid when used at high concentrations.
Of the thickening agents tested, XP showed the greatest overall potential for use as an acid gelling agent. This polymer is an efficient viscosity builder and has good stability in 15% HCl at temperatures up to 150°F. Computer model studies, which take into consideration cool-down and gel degradation rate at various stages of acid spending, indicate viscosity is maintained when treating wells that have bottomhole temperatures (BHT's) up to 220°F. Since the gelled acid retains its viscosity during spending, both reaction rate and fluid leakoff are retarded. Laboratory studies simulating downhole spending conditions yield a 3.6-fold increase in spending time for gelled 15% HCl (22-cp) compared with ungelled acid. Well test results are presented that demonstrate the effectiveness of acid fracturing treatments using HCl with XP.
Sulfur Plant Operations in Jay and Flomaton Fields
Authors: Henderson J.K. , Hudson C.W. , Kimble E.L. 
Published: December 2007

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

Introduction
The Jay field, discovered in 1970 and unitized in 1974, is in Florida's northwest panhandle.1 This sour-oil field producing from the dolomitized Smackover carbonate is producing 109,500 BOPD (corresponding to the permitted fieldwide SO2 emissions) with associated sweet-gas volumes of 140 MMcf/D. The full wellstream off-gas contains 10% H2S and 3% CO2. Nine separate crude-stabilization, sour-gas-treating, and sulfur-recovery plants have been designed and built to achieve a minimum 96% sulfur recovery as required by the State of Florida. The Flomaton sour-gas condensate field, 10 miles northwest of the Jay field in southern Alabama, produces from the Norphlet sandstone formation. This nonunitized field was discovered in 1968 and produces 2,600 B/D of stabilized condensate and 15 MMcf/D of sweet gas. The full wellstream gas contains 10% H2S and 40% CO2, for which the State of Alabama requires a sulfur recovery of 91%.
Operation of the Jay field treating facilities has provided experience in straight-through sulfur plants with various reheat designs such as acid-gas reheat burners, indirect reheat using steam, and hot-gas bypass reheat. The Flomaton sulfur plant uses a split-flow design because of the high CO2 content of its acid gas.
This paper reviews these sulfur plant operations including initial operating problems and solutions; sulfur plant maintenance procedures such as the annual plant turnaround activities, refractory repairs, and sulfur-boiler inspections; and daily operational surveillance and sulfur recovery testing for regulatory compliance. Sulfur plant safety procedures, emergency shutdowns, and operator-training programs for processing of toxic H2S gas also are described.
Flow Increase in the Trans Alaska Pipeline Through Use of a Polymeric Drag-Reducing Additive
Authors: Burger E.D. , Munk W.R. , Wahl H.A. 
Published: December 2007

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

Introduction
Drag reduction is a well-known phenomenon first observed in the laboratory almost 35 years ago.1 Although extensive experimental studies of drag reduction are continuing, the mechanism of drag reduction is not well understood. In spite of this limitation, there is a wide potential application for drag reduction in the oil industry in both production and transportation operations.
Drag reduction, as defined by Savins,2 is the increase in pumpability of a fluid caused by the addition of small amounts of an additive to the fluid. The effectiveness of a drag reducer is normally expressed in terms of percent drag reduction. At a given flow rate, percent drag reduction (DR) is defined asEquation 1
where ?p is the base pressure drop of the untreated fluid and ?pp is the pressure drop of the fluid containing drag-reducing polymer.
Percent drag reduction is a measure of drag-reducing additive performance, but it does not reflect the primary end use of drag reducers. Normally, the increased pumpability is used to increase flow rate without exceeding the safe pressure limits within the flow system. The relationship between percent drag reduction and percent throughput increase (TI) can be estimated using the following equation.3Equation 2
where %DR is the percent drag reduction as defined in Eq. 1. Eq. 2 assumes that pressure drop for both the treated and untreated fluid is proportional to flow rate raised to the 1.8 power.
The volumetric capacity and/or horsepower of the existing pumps may limit the amount of throughput increase. The installations of additional pump capacity may be necessary to obtain the full benefits of drag reducer use.
The use of drag reducers in the oil industry has been limited primarily to hydraulic fracturing operations.4 Water-soluble polymers have been effective in reducing hydraulic horsepower requirements and/or increasing pump rates during fracturing treatments. Many water gels used to improve the sand-carrying capacity of the fracture fluid have excellent drag-reduction properties. Oil-soluble polymers have been used to a lesser extent in hydraulic fracturing with oil-base fluids. Drag reducers have not been used routinely in standard crude oil pipeline operations.
A Successful Peripheral Water Flood in a Thin Pennsylvanian Reservoir
Authors: Wattenbarger R.A. , Howell B.L. , Loye P.E. 
Published: December 2007

Abstract
The Northeast Jones area of Oklahoma was discovered in 1945. Production peaked in 1948 and the area was almost depleted by 1950. Primary recovery was an economic failure and the field was almost abandoned without a trial of secondary recovery. There were several reasons for the pessimism regarding water flooding, but the most predominant was the old "rule of thumb" that secondary recovery would be the same as primary recovery. The Northeast Jones Cleveland sand unit was formed in 1952, however, with the promotion of an outside group of operators. The water flood proved to be very successful and lucrative, recovering over twice as much waterflood oil as primary oil. Peripheral injection was employed which eliminated the need to drill new wells and, in retrospect, made the project much more successful than would have a pattern water flood. The geometry of the water flood, the uniformity of the formation, and the high oil saturation are believed to be the major contributing factors to the high waterflood recovery and efficiency. Only 3.1 bbl of effective water injection were required for each barrel of oil recovered.
Introduction
Often, in engineering a prospective water flood, it is found that neither the data nor the applicable calculation methods are completely adequate. To some extent, previous experience is applied in these cases and comparisons are made to known field case histories. When the fields are, in fact, comparable, the predictions are valid. However, many times comparisons or rules of thumb are not valid and the results can be very expensive. In the case of the Northeast Jones, some operators had condemned water flooding because of poor primary recovery, using the old "rule of thumb" that waterflood recovery would approximate primary recovery. The area came close to being abandoned without secondary recovery, but a unit was finally formed and water flooding was very successful. Undoubtedly, if present waterflooding experience had been available at the time of decision on the Northeast Jones, there would not have been much doubt regarding water flooding. The value of case histories, then, is in providing an ample range of experiences so that valid comparisons can be made by the engineer for the purpose of prediction. This paper presents an analysis of the history, planning and performance of the Northeast Jones water flood.
Reservoir Development and Characteristics
The Jones Field, shown in Fig. 1, is composed of the Northeast Jones and West Jones areas. Each of these areas was originally considered as a separate field but production performance showed that they should be considered as one. The two areas are in communication but are partially separated by a permeability pinch-out in Section 27.The Cleveland sand reservoir is a stratigraphic trap of Pennsylvanian marine deposition. The reservoir is 4,600 ft deep and its producing thickness varies from 4 to 9 ft, averaging 6.5 ft.
JPT
P. 1238ˆ
Estimation of Tertiary Recovery by CO2 Injection - Springer A Sand, Northeast Purdy Unit
Authors: Simlote Vishnu , Withjack Eric M. 
Published: December 2007

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

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

Geological Description
The Springer A reservoir contains Lower Pennsylvanian rocks deposited as shallow marine sediments with environmental variations. The sand is a fine-to medium-grained siliceous sandstone dipping approximately 8 degrees southwest. Fig. 2 is a three-dimensional (3D) map showing the reservoir configuration. Data from core analyses indicate numerous tight zones within the gross pay section. Some cores show more than one well-defined pay zone, while others indicate only a single zone.
JPT
P. 808^
Peripheral Pattern Waterflood Performance, Sholem Alechem Fault Block "E" Unit
Authors: Denham Ralph R. 
Published: December 2007

Abstract
Predictions of primary performance and five-spot water-flood performance were made early in the life of the Sholem Alechem fault block "E" field. A fieldwide secondary-recovery unit was formed near the end of primary depletion and the reservoir was water flooded using a peripheral injection pattern. By comparing the five-spot waterflood prediction with the actual peripheral waterflood performance, we established that five-spot predictions of oil recovery, water production and water injection can be used to determine the same performance characteristics throughout the life of a peripheral water flood. Accomplishing and determining fill-up are necessary for the satisfactory operation of a peripheral water flood in a previously depleted reservoir. Methods of positively determining fill-up as well as inconclusive indications of fill-up are discussed. After fill-up it is possible to make a pore-volume calculation of waterflood reserves utilizing flood-front data and new saturation conditions, which will serve as a check on the previous estimates of waterflood reserves.
Introduction
The Springer Sims sand reservoir in the fault block "E" area was initially produced in 1948. The reservoir was developed on 10-acre spacing, and the unitized area includes 47 wells. Reservoir characteristics are included on Table 1.The reservoir is a portion of the Springer anticline structure, which has been separated by major faulting. A combination of normal block faulting followed later by reverse faulting together with sand development has divided the area into several essentially closed reservoirs. The Sholem Alechem fault block "E" unit (SAFBEU) was formed from the oil-producing portion of an essentially separate reservoir. The area is closed on the north by a fault and sand development, on the west by a fault. on the east by sand development and on the south by a water-oil contact. This is shown in Fig. 1.The reservoir originally had a gas cap and an aquifer. During primary depletion the reservoir produced principally as dissolved-gas-drive reservoir with some gas-cap expansion. Although some water was produced from down-dip wells and there was a noticeable encroachment of water before unitized operations began. there was no appreciable recovery resulting from the water influx. During 1953 the unitization engineering subcommittee evaluated primary and five-spot waterflood performance for the proposed unit area. These predictions and actual production during the primary and waterflood phases of operation are shown on Fig. 2.
JPT
P. 537ˆ
Restoration of Groundwater Quality Following Pilot-Scale Acidic In-Situ Uranium Leaching at Nine-Mile Lake Site Near Casper, Wyoming
Authors: Engelmann William H. , Phillips P. E. , Tweeton Daryl R. , Loest Kent W. , Nigbor Michael T. 
Published: December 2007

Abstract
The results of the first restoration effort for a pilot-scale acidic leaching of a uranium ore body in the U.S. are given. The project was performed under a cooperative agreement between the USBM and a joint venture consisting of Rocky Mountain Energy, Mono Power Co., and Halliburton Co. The leaching phase is described only briefly; it was reported earlier by Tweeton et al.1 Leaching was done with H2SO4 (pH range of 1.6 to 3.9) and H2O2 (80 to 1,000 ppm) over an 11-month period.
The restoration phase began in September 1978 and was completed in 11 months. Water samples were taken from observation wells located between injection and production wells while the leaching solution was decreased in strength. Groundwater quality in the leached ore zone was restored by diluting and neutralizing effects of injecting native groundwater and treated water produced from recovered solution. Recovered water was purified by a combination of chemical precipitation and reverse osmosis. In-situ measurements of pH, Eh, dissolved oxygen, conductivity, and temperature were made by a downhole probe in one of the wells. Water samples were taken and analyzed for U, V, Na. K, Ca, Mg, SO4. P, Cl, F, Fe, Mn, Si, Zn, As, and Se.
Use of Hydraulic Fracturing Equipment for Formation Sand Control
Authors: Rawlings H. Earl 
Published: December 2007

Introduction
Beginning early in the history of producing oil from subsurface strata, the industry has been constantly searching for efficient economical means of controlling the movement of unconsolidated formations into the wellbore. During the past 25 years, numerous investigations of various gravel screening media and their characteristics have been very satisfactorily carried out, demonstrating to the industry that sand or gravel properly selected and placed can effect formation sand control and not damage productivity. In the past years the use of gravel in wellbores for this purpose has met with varying success.
Gravel or sand size selection for various formation conditions has been previously investigated.
Early research and field applications of a gravel screening medium to unconsolidated oil-bearing sands were confined to only the problem of controlling the movement of these sands into the wellbore. It was early recognized that the more firmly such a screening medium could be placed against a producing formation, the more successful the pack would be in controlling movement. A satisfactory method and equipment for placing the packing material under pressure has long been desired.
The mechanics of strata penetrated by wellbores have been under study for many years. Some of the developed theories vary even with ideal matrix. The unconsolidated oil-bearing sands conform to mechanical patterns that are even more highly controversial. The most common effect of stresses within these formations is movement of the formation particles. Secondary, but notable, is the usual rapid production decline in some of them.

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

Abstract
In a concentric cylinder viscometer, Utah shale oils have different characteristics, both at equilibrium flow and during start-up from rest, depending on whether the wax has crystallized as needles or spherulites. Compared with waxy crude oils, which are thixotropic, shale oil has the added rheological property of being antithixotropic.