bluuebunny/crossref_metadata_2025_split huggingface dataset:
Stickiness Factor—A New Way of Looking at Stuck Pipe
Authors: Love T. E. 
Published: December 2007

ABSTRACT
The stickiness factor is an empirically derived number strongly related to the chances of freeing stuck pipe in a well. The number is defined by the following equation: (1)Stickiness Factor =(∡ + 10°)(OH + 5000')(MW2)×(2 + FL)(BHA+800')1×1011
where: ∡ is the maximum angle in the open hole (degrees); OH is the amount of open hole (feet); MW is the mud weight (lb/gal); FL is the API-fluid loss (cc/30 min); and BHA is the bottom-hole-assembly length (feet).
The relationship between the stickiness factor and the historic chances of freeing stuck pipe is illustrated by the chance curve of Figure 1. Basically, the stickiness factor should be kept below 2.5 wherever practical. Since stuck pipe costs are largely dependent on the ability to free stuck pipe and avoid sidetracking a well, it follows that reduced stickiness factors should result in reduced stuck pipe costs. The stickiness factor is commonly lowered by reducing the API-fluid loss of the mud, reducing the bottom-hole-assembly length, or setting casing.
The stickiness factor is based on a study of Gulf of Mexico wells drilled by Exxon Company, USA. Therefore, it will not necessarily apply well in other areas. The factor does. not predict when pipe will stick, but simply predicts the chance of freeing pipe that has already been stuck.
The stickiness factor will also help evaluate various spotting fluids and fishing techniques since it indicates the relative difficulty (chance of success) of a soaking or fishing job.
Finally, a reduced stickiness factor should reduce the chances of sticking pipe.
How and When to Run a PDC Bit in the Upper Texas Gulf Coast—An Operator's Viewpoint
Authors: Cress L. A. 
Published: December 2007

Abstract
PDC bits have become a recognized part of new technology in the oilfield. But, the coming of age of this type bit has necessarily required a considerable amount of field test results to be able to make an economic performance analysis. The problem, is knowing when good data is being analyzied and how to make an engineering recommendation to use a PDC bit.
A Review of the Environmental Acceptability and the Toxicity of Diesel Oil Substitutes in Drilling Fluid Systems
Authors: Thoresen K. M. , Hinds A. A. 
Published: December 2007

Abstract
The passage of the National Environmental Policy Act (NEPA) in 1969 and heightened concern for the environment has led to increased government regulation, especially in environmentally sensitive areas such as the Georges Bank, The Flower Gardens, and offshore California. At the same time oil exploration and drilling in these areas have been increasing. The discharge of diesel oils and cuttings containing diesel oil from offshore drilling platforms is a major concern since diesel oil is known to be toxic to marine life. Current regulations prohibit the discharge of oil based muds and unwashed cuttings from drill rigs.
The primary bases for determining the environmental acceptability of an oil, are the regional, national, and international water quality criteria for discharges.
Any potential substitutes for diesel oil must be acceptable to the operator as well as the regulating agencies. A comparison of the composition, chemical and physical characteristics, and toxicity of various animal, vegetable, and petroleum oils suggests that white mineral oil (a highly refined petroleum oil) is a potential substitute for diesel oil in drilling fluid systems.
Diesel oil and white mineral oils are compared in a review of toxicity, and environmental impact studies including persistence, degradation, and bioaccumulation data. The paraffinic, cycloparaffinic, aromatic and polynuclear composition of diesel oil and white mineral oils are examined. The aromatic hydrocarbon content and certain polynuclear aromatic compounds appear to be the main source of toxicity in hydrocarbon based oils. The relatively low toxicity of white mineral oil is attributed to the absence of high concentrations of these polynuclear aromatics.
Case studies show that white mineral oil performs well in drilling muds. The discharge of cuttings (containing absorbed white mineral oil) has been sanctioned by some EEC countries. The development and use of non-toxic oils in drilling fluid systems raises prospects for the direct disposal of drilled cuttings and spent muds offshore, resulting in lower mud maintenance and disposal costs for the operator.
Drilling Improvements Using Power Swivels
Authors: Zinkgraf H. L. , Hammett D. S , Boyadjieff George 
Published: December 2007

Abstract
This paper presents the technical advances made in the use of power swivels in replacing the rotary table. The equipment, drilling techniques and accelerated drilling time are reported. Specifically, special features of the use of a power swivel are also presented, i.e., drill up, remote pipe stabs, safety, operating cost reduction, drilling down 90 ft. stands. The object of this report is to acquaint people with the recent advances in the use of the power swivel.
Chargers for Better Piston Pump Performance
Authors: Collier S. L. , Jefferies R. K. 
Published: December 2007

Abstract
Today's economy requires that greater attention be given to improve performance of drilling equipment. Understanding the operation of the piston (slush) pump and the associated mud system is vital to improving operations. Improved operation of the piston pump is achieved by providing a mud supply which insures proper filling of the piston pump on each stroke. Testing in a high pressure mud pump research laboratory provided the substantiation of the analytical design approach presented in this paper.
A Proven Elastomer Compound for Extremely Hostile Geothermal and Oilfield Environments
Authors: Hirasuna A. R. , Friese G. J. , Stephens C. A. 
Published: December 2007

Abstract
Since 1979 the Y267 EPDM elastomer has been independently tested by other organizations in a variety of field and laboratory applications. The following are some examples. The same &267 EPDM O-rings worked with no leaks as logging tool seals for multiple trips to 4600M (15k ft.) at 320C (608F) BHST. A packer element performed flawlessly for five months in a 204C (400F) continuous steam injection well and was retrieved at the end of the test in an as-new condition. A high-pressure Y267 EPDM packer test was performed with complete success at 232C (450F) for a 7.5 day test in sour crude with differential pressures to 138 MPa (20 ksi) and the seal condition was only very slightly changed by the test. Comprehensive compatibility testing of 34 compounds from 15 companies in geothermal brine, isobutane, and oil at 191C-266C (375-510F) showed that the Y267 EPDM was best of the 34 in all three fluids.
Over 15 laboratory and over 20 field case histories of Y267 EPDM such as the above examples are reported. All strongly establish that Y267 EPDM is at the cutting edge of technology.
Status Of Thermal Recovery
Authors: Howard J.V. 
Published: December 2007

Abstract
Thermal recovery of oil has received a large increase in interest in the past year. Steam and hot-water flooding, forward combustion and cyclical steam injection are considered. A brief review of forward combustion and the techniques used to predict its performance are discussed. The predictive techniques for hot-water and steam floods are discussed. A discussion of cyclical steam injection is made, and the lack of a predictive technique in the literature is stressed. Some of the basic considerations in predicting the performance of cyclical steam injection are presented. Conclusions are reached that reasonable methods exist for the prediction of forward combustion, hot-water and steam flooding and that none exists in the literature for steam stimulation.
Areal Sweep Efficiency Increases By Scheduled Changes Of Injection-Producing Patterns
Authors: Oakes Dave T. , Bunch W.H. 
Published: December 2007

Abstract
Results and procedures are presented which demonstrate a novel means Of changing the injection and producing pattern (rotation) to increase substantially the areal sweep efficiency and recovery during pattern water flooding. Two types of laboratory tests were made. One series was made On sand-packed areal models utilizing oil and water solutions with an oil-water viscosity ratio of approximately 1. A second series of tests was made on Hele-Shaw (fluid mapper) models utilizing glycerol solutions to represent both oil and water with mobility ratios of 1, 3.5 and 9.2.
Based on the sand-packed model studies, it is concluded that by injecting into the center well a volume of water equal to approximately 50% of the volume normally required for breakthrough, then rotating the injection into a diagonal opposite well, the areal sweep efficiency at breakthrough and at a water-oil ratio of 90:1 is increased 5–8% as compared to conventional five-spot flooding. This would mean an increase in oil recovery of about 6–9%.
From the fluid mapper studies it is concluded that:
at a mobility ratio of 1, the areal sweep efficiency is increased by approximately 10% by a scheduled rotation that does not entail shutting in the center well, but maintains a given injection ratio (1:5.9) between the center and offset diagonal wells, at a mobility ratio of 1, the areal sweep efficiency of an inverted nine-spot rotated to a five-spot is also increased by approximately 10%; the areal sweep efficiency at adverse mobility ratio is reduced due to viscous fingering. However, an increase in sweep efficiency over conventional five-spot flooding continues to be observed on the rotated tests.
High Efficiency Fracturing Fluids for High Temperature Reservoirs
Authors: Baumgartner S. A. , Parker C. D. , Williams D. A. , Woodroof R. A. 
Published: December 2007

ABSTRACT
Reservoirs with bottomhole temperatures in excess of 250°F are commonly encountered in the ever-expanding search for hydrocarbons. Successful completion of these wells often requires the use of Massive Hydraulic Fracturing (MHF) treatments.
The fracturing fluids used in MHF treatments are frequently subjected to excessive shear and prolonged exposure at high bottomhole temperatures. Early fracturing fluids proved unsuitable for these MHF treatments due to a rapid loss of viscosity at high temperatures. As a result, narrow fracture widths, excessive fluid loss and poor proppant transport occurred. Cool-down pads, increased polymer concentrations and delayed polymer hydration systems were employed in an attempt to improve the MHF treatment success ratio.
A laboratory investigation was undertaken to develop a more efficient high temperature fracturing fluid. Rotational and pipe viscometers were used to evaluate thermal and shear stabilities at reservoir conditions. Fluid loss testing measured the control of fluid leakoff to the formation. Fluid breakout testing ensured a controlled loss of viscosity and rapid cleanup. As a result of this study, a more efficient high temperature fracturing fluid was developed.
This paper presents laboratory data comparing the thermal stability, shear stability and fluid loss control of the High Temperature Gel (HTG) with those of a conventional titanate crosslinked gel. Field case histories are presented to demonstrate the efficiency with which HTG has been used to successfully stimulate wells with bottomhole temperatures in excess of 250°F.
Gas Well Operation With Liquid Production
Authors: Lea J. F. , Tighe R. E. 
Published: December 2007

ABSTRACT
Prediction of liquid loading in gas wells is discussed in terms of intersecting tubing or system performance curves with IPR curves and by using a more simplified critical velocity relationship. Different methods of liquid removal are discussed including such methods as intermittent lift, plunger lift, use of foam, gas lift, and rod, jet, and electric submersible pumps. Advantages, disadvantages, and techniques for design and application of the methods of liquid removal are discussed.
Geologic and Engineering Analysis of Blanket-Geometry Tight Gas Sandstones
Authors: Finley R. J. , O'Shea P. A. 
Published: December 2007

ABSTRACT
A comparative survey of over 30 blanket-geometry tight gas sandstones in 16 sedimentary basins was prepared for the Gas Research Institute. For each stratigraphic unit a uniform set of information was obtained on general attributes, economic factors, geologic parameters of the basin and the formation, reservoir engineering data, and operating conditions. Each tight gas reservoir was considered within a sedimentary framework of associated lithogenetic facies that make up a depositional system. In contrast to lenticular sandstones, which are primarily fluvial deposits, blanket-geometry tight gas sandstones were deposited as deltaic, barrier strandplain, and shelf systems. The reservoir geometry resulting from the deposition of blanket sandstones is expected to mitigate selected reservoir engineering problems associated with tight gas sand development. Results of this survey are being utilized in a more detailed study, now underway, which will ultimately lead to the selection of two prospective field test areas, possibly consisting of individual stratigraphic units, geologic basins, or depositional systems.
Predicting Turbidite-Contourite Reservoir Intervals in Tight Gas Sands: A Case Study From the Mancos B Sandstone
Authors: Witherbee L. J. , Godfrey R. D. , Dimelow T. E. 
Published: December 2007

ABSTRACT
The Mancos B Zone is a classical tight gas formation, considered an attractive exploration target along the Douglas Creek Arch due to its widespread distribution. The unpredictable success of such wells led to a regional study investigating the environment of deposition, the nature of the porosity, and the relationship between lithology and log response in the Mancos B. Potential reservoir intervals can be differentiated successfully from non-reservoir intervals by integrating the results of detailed lithologic and wireline log analysis.
A Coordinated Seismic Study of the Multi-Well Experiment Site
Authors: Searls C. A. , Lee M. W. , Miller J. J. , Albright J. N. , Fried Jonathan , Applegate J. K. 
Published: December 2007

Abstract
A series of seismic studies were performed at the Department of Energy Multi-Well Experiment site to delineate the character of the beds within the Mesaverde group in western Colorado. The experiment consisted of a three-dimensional seismic survey of the area, a vertical seismic profile of the two wells and a cross borehole survey covering zones of special interest. The combined analysis of these data and well log and core information was used to relate the seismic records to the geology of the area.
Liquid CO2 for the Stimulation of Low-Permeability Reservoirs
Authors: King S. R. 
Published: December 2007

ABSTRACT
The effects of residual fluid in the stimulation of low permeability reservoirs has long been a problem. The use of conventional fracturing fluids (water or oil) in tight reservoirs, especially those considered to be dry gas sands, generally results in the loss of 50-75% of the fracturing fluid. Total recovery of the conventional fracturing fluid is usually never accomplished as the fluid becomes immobile at irreducible saturation. The use of liquid carbon dioxide (CO2) as a fracturing fluid was developed to combat the problems of fluid imbibition that are encountered with conventional fluids. The liquid CO2 fracturing system is essentially a non-damaging system that reverts to a gaseous state at static formation conditions. The CO2 is then returned to the surface under controlled rates as a gas. The result being a more rapid cleanup and evaluation of the well following the treatment.
Development of a Fully Three-Dimensional Simulator for Analysis and Design of Hydraulic Fracturing
Authors: Cleary M. P. , Kavvadas Michael , Lam K. Y. 
Published: December 2007

ABSTRACT
This paper describes our formulation and numerical implementation of the framework for a full three-dimensional hydraulic fracturing simulator (3DHFRAC). Solid rock deformation is described by efficient singular integral equation techniques and fluid flow in the fracture is captured by effective viarational/finite-element methods. The choice of (local vs. global) interpolation techniques allows the same mesh to be used for both processes, and major mesh regeneration costs are greatly reduced. The computationally prohibitive problem of fluid flow near and propagation of the fracture perimeter is rendered tractable by means of a leading-edge concept, which draws on existing experience with simpler models. Testing of the model components is demonstrated by solving some crack-opening and fluid flow problems with existing solutions; then the overall model is verified with reference to our simpler models, for circular, CGD and P3DH-type fracture geometries. Further, the containment role of barriers to fracture growth specifically confining stress variations between reservoir and adjacent strata is demonstrated; the more general potential of the model to describe the role of the many other mechanisms is emphasized, thus allowing calibration of simpler models or even direct use for treatment design.
The Application of a New Second-Generation High-Strength Proppant in Tight Gas Reservoirs
Authors: Callanan M. J. , Cipolla C. L. , Lewis P. E. 
Published: December 2007

ABSTRACT
An analysis is made to illustrate the effectiveness of a new second generation high strength low density proppant as compared to that of sintered bauxite and Ottawa sand in a variety of applications. This is accomplished through the use of a reservoir simulator and a fracture design program. Gas producing formations are simulated which exhibit permeabilities between 0.001 md and 0.1 md and closure stresses up to 9500 psi. In these simulations the second generation proppant and sintered bauxite yield essentially identical production histories. However, the second generation proppant shows far superior performance to Ottawa sand in all applications. Also shown are cases revealing that tail-ins with the second generation proppant can yield a higher return on investment than pumping all high strength proppant.
The simulations reveal the importance of non-Darcy flow and conductivity damage considerations in proppant selection. It is shown that these two factors have much less of an effect on the performance of the second generation proppant than on that of sand. With all of this considered the second generation proppant should prove to have a substantial economic advantage over both sintered bauxite and sand in a variety of applications.
Reservoir Simulation of the Falher Conventional/Low Permeability System: Corrected to Insitu Conditions
Authors: Dawe B. A. 
Published: December 2007

Abstract
Indentification of the recovery mechanism for the more permeable conglomerate/low permeability sand system in the Falher formation in Alberta, Canada was accomplished by reservoir simulation of single wells. Reservoir properties of porosity, permeability, and water saturation were corrected to insitu conditions.
Results show that vertical percolation of gas from the low permeability sand into the conglomerate is generally not the rate limiting factor due to the large areal contact between the two intervals. Gas recovery from low permeability sands is controlled by very low permeability high water saturation zones* These zones become effective barriers in the ten nano-darcy range.
Production Data Reporting and How it Aids Surveillance in Thermal Recovery Fields
Authors: Dever R. E. , Womack F. A. 
Published: December 2007

Summary
Modern surveillance requirements in large thermal recovery oil fields overwhelm manual efforts at collection, retrieval, and reporting of operations and production data. The introduction of a customized data base management and reporting system for this purpose can benefit Operations and Engineering through 1) increased production from timelier awareness of field operating conditions, 2) reduced operating expenses, 3) better steam utilization, and 4) significant manpower productivity increases.
Unitizing and Waterflooding the California Yowlumne Oil Field
Authors: Burzlaff A. A. 
Published: December 2007

Abstract
The Yowlumne field, located at the southern end of the San Joaquin Valley of California, is one of the largest new onshore oilfields discovered in California in the past twenty years. The field, at an average depth of 12,200, has produced over 42 million barrels of oil since its discovery in 1974.
In May, 1982, a portion of the Yowlumne field was unitized and called Yowlumne Unit "B". Nine operators and about 160 royalty owners cooperated to form this unit. A two phase unitization formula based on 1) remaining primary and 2) initial hydrocarbon pore volume was used to form Unit "B". A secondary waterflood project is being implemented which is estimated will increase oil recovery by some 25 million barrels.
Softening of Oilfield Produced Water by Ion Exchange for Alkaline Flooding and Steamflooding
Authors: Reyes R. B. 
Published: December 2007

ABSTRACT
Oilfield "produced" waters usually contain high hardness, and high dissolved solids along with some alkalinity. The problem of disposing of these waters and the need for huge volumes of water for alkaline water flooding and steam generation for steam floods, necessitate the softening and reinjection of softened produced water. Water for alkaline and steam flooding needs to be softened to almost zero hardness to prevent plugging during injection and to prevent scaling on boiler tubes.
Softening of high TDS and high hardness waters requires a very selective resin with high operating capacity such as a weak carboxylic acid-type ion exchange resin. Conventional softening with strong acid resins would not work under these conditions.
This paper discusses the different processes in softening oilfield produced water. Data obtained in softening varieties of produced waters from different oilfields in California will be presented. Performance characteristics of weak cation exchange resins and their chemical regenerant requirements will also be discussed.
An Analysis of Stimulation Treatments of the Randolph Sand in the Semitropic Field, Kern County, California
Authors: Mitchell M. D. , Chamberlain C. R. 
Published: December 2007

ABSTRACT
The Semitropic field is located approximately ten miles west of Wasco in the San Joaquin Valley of California. The original productive zones in the field were the Mya and the Mulinia gas sands occuring at depths of 2,200′ to 4,400′. In the last six years, the Randolph Oil Sand at 7,800′ has been actively developed and is now the major productive interval. Recently, several of the Randolph wells have been stimulated with hydraulic fracturing treatments. A majority of these wells have shown productive increases of varying degrees depending upon field location, job volume and proppant size. This paper will discuss the geologic production history of the Randolph Zone, completion techniques, reservoir characteristics and stimulation design and treatments.