bluuebunny/crossref_metadata_2025_split huggingface dataset:
Supercharge Pressure Compensation Using a New Wireline Testing Method and Newly Developed Early Time Spherical Flow Model
Authors: Proett Mark A. , Chin Wilson C. 
Published: December 2007

Abstract
Wireline formation testers are increasingly being used to obtain formation pressure and permeability measurements, which in turn are used in geological evaluations and in designing well completions. It is generally assumed that the pressure measured by the tester probe is near formation pressure. Unfortunately, in many instances, such as in low permeability formations, the mudcake does not adequately isolate the hydrostatic pressure in the wellbore from the formation. As a result, the sandface pressure measured with the formation tester is "supercharged" and not the formation pressure after all. This sandface pressure may be as much as 1,000 psi over the actual formation pressure of interest. This paper demonstrates that a new analytical model can be used along with a new testing technique to correct the measured pressure to actual formation pressure. A high accuracy finite element near-wellbore simulator (NEWS†) is used to test the sensitivity of the analytical model. Log examples are presented to demonstrate the success of the new testing technique.
The Determination and Considerations of Induced Fracture Strike
Authors: Blomberg John R. 
Published: December 2007

Abstract
The determination of induced fracture strike is an important factor in both the primary and secondary development of oil and primary and secondary development of oil and gas reservoirs. If a common strike can be substantiated for a field or area, ultimate recoveries can be increased through exploiting the reservoir on a development pattern that conforms to the induced fracture strike.
This paper is a practical discussion of the use of the Borehole Televiewer log in wells in the Appalachian basin to determine induced fracture strike. Log sections are presented and various applications of results are discussed. Two anomalous cases are also presented and discussed.

Introduction
The importance of determining the strike of induced or natural fractures has been recognized for some time. Early work with the Lynes packer and more recent work with softer rubber packer and more recent work with softer rubber impression packers have provided information about the strike and configuration of both natural and induced fractures. However, the impression packer procedure is sometimes costly, time-consuming and the orientation procedure at times questionable. In 1968, an open-hole logging tool patented by Mobil was introduced to the industry to define fractures and give an accurate orientation in a simple logging operation. This tool has generally given good results in wells logged in the Appalachian basin, and the results have easily been interpreted.
More emphasis has been placed on the application of fracture orientation data to planning secondary recovery. However, if planning secondary recovery. However, if primary development wells are completed with a primary development wells are completed with a fracture treatment, secondary recovery potential with respect to fracture orientation must be considered from the start of initial field development.
One of the most significant field secondary recovery developments, based on indicated natural fracture strike, was the waterflood development of the Spraberry field in West Texas. Waterflood patterns were designed to conform to the natural major fracture system to maximize sweep efficiency. Several operators have installed secondary recovery project patterns to conform to the induced fracture strike, patterns to conform to the induced fracture strike, but very little is available in the literature as to how successful these efforts have been.
Application of a Transient Heat Transfer Model for Bundled, Multiphase Pipelines
Authors: Brown Trent S. , Clapham John , Danielson Thomas J. , Harris Robert G. , Erickson Dale D. 
Published: December 2007

Abstract
A computer model has been developed which accurately describes transient heat transfer in pipeline bundles. An arbitrary number of internal pipelines containing different fluids, flowing in either direction along with the input of heat to one or more of the fluids can be accommodated. The model is coupled to the transient, multiphase flow simulator OLGA. The lines containing the multiphase production fluids are modeled by OLGA, and the heat transfer between the internal lines, carrier pipe, and surroundings is handled by the bundle model.
The model has been applied extensively to the design of a subsea, heated bundle system for the Britannia gas condensate field in the North Sea. The 15-km bundle system contains a 14″ production line, an 8″ test line, a 3″ methanol line, and a 12″ internal heating medium line within a 37.25″ carrier. The heating medium (water) flows in the internal heating medium line and in the annulus at 82,500 BPD. The primary purpose of the bundle system is to avoid the formation of hydrates. A secondary purpose is to avoid the deposition of paraffin. The bundle model was used to 1) compare the merits of two coaxial lines vs. a single bundle; 2) optimize the insulation levels on the carrier and internal lines; 3) determine the minimum time required to heat up the bundle; 4) determine heat input requirements to avoid hydrates throughout the field life, 5) determine temperature profiles along the lines for a range of production rates; 6) study ruptures of the production line into the bundle annulus; 7) determine minimum temperatures during depressurization; and 8) determine cool-down times. The results of these studies were used to size lines, select insulation levels, assess erosion potential, design for thermal expansion-induced stresses, and to select materials of construction.
The Influence of Drilling Variables on Barite Sag
Authors: Bern P. A. , Zamora M. , Slater K. S. , Hearn P. J. 
Published: December 2007

Abstract
Barite sag is a significant variation in mud density caused by the settlement of barite or other weight material in high-angle wells. The wide fluctuations in mud weight can lead to severe operational problems, including well-control, induced wellbore instability, downhole mud losses, and stuck pipe.
A laboratory flow loop has been used to evaluate the influence of key drilling parameters on barite sag. Results show that the highest sag occurs at angles in the region 60-75°, particularly at low annular velocities. Drillpipe rotation is shown to be particularly beneficial in minimising barite settlement. Rotation also assists in re-distributing barite deposits formed on the low side of the hole. Data from the tests clearly demonstrate the interdependence of drillpipe eccentricity, rotation, and mud flow rate.
Results from the study have been combined with field observations to develop guidelines to minimise barite sag and manage the associated risks. The conclusions of the study are that barite sag can be minimised by attention to detail at the planning and execution stages of drilling a well. In particular, recommendations in four key areas are addressed: well planning, mud properties and testing, operational practices, and wellsite monitoring procedures.
Thermal Stimulation and Mechanical Techniques Permit Increased Recovery from Unconsolidated Viscous Oil Reservoir
Authors: Holke David C. , Huebner William B. 
Published: December 2007

Introduction
The Northeast Butterly Oil Creek unit is located in Garvin County, Okla., along the northern flank of the Arbuckle Mountains. Production from this field is from the Basal Oil Production from this field is from the Basal Oil Creek sand of the Simpson group, Ordovician age, at an average depth of 4,200 ft. The formation is characterized by a relatively homogeneous sand section, which is mostly unconsolidated with limey streaks through the section. The porosity is 24.3 percent with the median porosity is 24.3 percent with the median horizontal and vertical permeabilities to air 850 and 700 md, respectively. Total pay thickness is 143 ft. The natural producing mechanism is an active water drive.
The field is considered an anticlinal high, buttressing a major fault with many cross faults dividing the pool as shown in Fig. 1. Dips as high as 40 degrees exist in many parts of the field.
Encompassing only 165 acres, this field has produced 3,575,000 bbl of oil; total original produced 3,575,000 bbl of oil; total original oil in place is estimated to be 27 million bbl. It is the purpose of this paper to share some of the technology that is being used to produce this 13 degrees API gravity crude. Through the use of thermal stimulation and mechanical techniques, the recovery of this viscous, highly emulsified, sand-laden fluid has been accomplished. Reservoir and fluid characteristics are shown in Table 1.
PRIMARY PRODUCTION Because of its reserves and potential production, the Northeast Butterly Oil Creek production, the Northeast Butterly Oil Creek reservoir has attracted considerable engineering attention since its discovery. Peak production was in Aug., 1948, at a rate of 1,650 B/D. Most wells were completed for greater than 200 B/D.
A total of 13 wells were drilled from 1946 to 1948, of which one was a dry hole and one was plugged because of mechanical difficulties. As plugged because of mechanical difficulties. As wells reached high water-oil ratios, they were shut in due to being uneconomical and for lack of disposal facilities. Production declined to 3,500 bbl/month from 1957 until 1964, when thermal activities were initiated (Fig. 2).

THERMAL STIMULATION
The viscosity of the Butterly crude is approximately 2,000 cp at reservoir conditions. As can be seen on the viscosity-vs-temperature curve (Fig. 3), by raising the reservoir temperature 100 degrees F or more, the crude viscosity can be appreciably reduced. With this fact in mind, a preliminary investigation was made in 1959, followed by a feasibility study in 1962 to determine the applicability of thermal stimulation at Northeast Butterly.
Shale Drilling with Oil Muds
Authors: Methven Norbert E. , Barthel Horst 
Published: December 2007

Abstract
Significant strides have recently been achieved in minimizing shale problems while drilling. A primary contribution is the use of oil base mud wherein the chemical potential of any water phase in the mud is balanced with the chemical potential of the formation to preclude a reaction between the two.
This paper presents a summary of shale and clay theory and laboratory data to aid the definition of wellbore stability problems. These data include water content versus relative vapor pressures for clays and shales which can be related to downhole conditions for establishing the optimal properties of an oil mud aqueous phase. Also included are relative vapor pressure data for aqueous phases with various salts and concentrations. phases with various salts and concentrations. These data are then used to prescribe the mud properties to preclude wellbore instability properties to preclude wellbore instability while drilling.
Compromises are necessary when trying to match the aqueous phase of a mud to the requirements of the formation. These compromises occur when information is not available in the region of interest. Also compromise occur often because the exposed shales in a well will have varying requirements, but will be exposed simultaneously to a single mud system. Another case occurs when drilling through salt sections which causes the aqueous phase of a mud to be altered. The sensitivity phase of a mud to be altered. The sensitivity of such compromises is aggravated by time of exposure and by high water content oil muds. Therefore, these compromises can be critical where invert oil emulsion muds are used because they require high water percentages in order to function.
An oil base mud does not require water to function. Therefore, the effects of these compromises can be avoided with the use of an anhydrous oil base mud or can be minimized with/the use of a low water content oil base mud. Laboratory and field data confirm these principles and are included in this paper.
Sand Exclusion by Pressure Packing Through Perforations
Authors: Shyrock S.H. , Watkins W.R. 
Published: December 2007

Abstract
Entry of formation fines and sand into oil and gas producing wells has been a continuing problem for many years. Methods of controlling problem for many years. Methods of controlling this entry have been developed and many fine papers presented on their merits. papers presented on their merits. In this paper, the authors suggest a method which was developed to reduce the cost of well completions and provide greater versatility in down hole control to those drilling wells for production from poorly consolidated sandstone production from poorly consolidated sandstone formations.
One major difference in the method described in this paper is that of attempting to obtain total sand exclusion. Earlier methods have been successful in obtaining sand control, but some small amount of sand or fines might still enter the well and damage the tubular goods.
Placement of a gravel media surrounding the perforated casing extending through the productive perforated casing extending through the productive zone can often be difficult, particularly in wells directionally drilled and having long or multiple producing zones. This method, which we have chosen, producing zones. This method, which we have chosen, to call "Pressure Packing Through Perforations," has proven not to be as difficult nor as expensive.
The application of this method to several wells located in the Oak Park Field, Ventura County, California, are discussed along with the description of the technique. It is believed that this method can well have application to oil and gas fields throughout the world where sand control or exclusion is desired.

Introduction
When one becomes concerned and seeks to find a method to exclude formation sand entry, it should be recognized that in order to accomplish this, one thing necessary to know is what size the pack sand must be. Formation sampling in these poorly consolidated formations is no easy task and often is thought to be impractical. The practice has been to use the smallest practical sand size in lieu of formation sampling, which if all other features of the technique are optimized, provides a reasonable degree of confidence.
Excellent papers have been published dealing with formation sampling and pack sand selection. In order to present this technique criteria adequately, we will forego quoting exerts from these publications, but suggest your referring to them.
Successful Drilling of an Underbalanced Horizontal Well in the Rigel Halfway Pool - Laboratory Screening and Field Results
Authors: Doane R. D. , Bennion D. B. , Eilers D. M. , New E. R. 
Published: December 2007

Abstract
The Middle Triassic Halfway formation in northeastern British Columbia is a high quality, well sorted quartzose sublitharenite. Past drilling operations using conventional overbalanced technology in the reservoir had indicated significant formation damage occurred due to a combination of mechanical and chemical formation damage effects associated with the loss of drilling fluid to the formation. A series of compatibility and special core analysis tests were conducted to refine an underbalanced drilling procedure with natural gas for a 300 m long horizontal well in the formation using a natural gas-mist hydrocarbon system at a 1400 kPa underbalance pressure level. The well was drilled successfully and flowed at peak rates of up to 1100 m3/day (almost 7000 bbl/day) of oil and 340,000 m3/day (12,000,000 scf/day) of gas during the underbalanced drilling operation. Post test pressure transient and interference tests indicated an in-situ permeability of 150 mD with zero skin factor indicating that the well had been drilled successfully in an undamaged fashion. The well has currently produced close to 13,000 m3 of oil (80,000 bbl) and over 11,000,000 m3 (400 MMscf) of gas with initial AOF potential of approximately 520 m3/day (3300 bbl/day).
State-Of-The-Art Cuttings Transport in Horizontal Wellbores
Authors: Pilehvari Ali A. , Azar J. J. , Shirazi Siamack A. 
Published: December 2007

Abstract
In the ever growing directional and horizontal drilling, hole cleaning is a common and costly problem. It can become particularly critical in the case of extended reach drilling, where larger and longer wellbores are drilled. During the past two decades, especially in the recent years, many laboratory studies as well as field observations have been directed to address the cuttings transport problem. This has resulted in better understanding of the subject, and some remedies to overcome the problems. Several correlations/models have also been developed which give the field engineer a tool to better specify hydraulic requirements to clean the hole. However, due to the complexity of the subject, a comprehensive and proven model, not existing at this time, requires much more laboratory research and field studies. This will be the major topic addressed in this article.
Pseudo-Horizontal Well: Alternative to Horizontal and Vertical Wells
Authors: Zakirov S. N. , Zakirov E. S. 
Published: December 2007

Abstract
Horizontal wells are getting more and more widely used in oil and gas fields development due to plenty of its merits. However, there are examples when horizontal well drilling did not justify hopes. It is shown in this paper, that layered and anisotropic structure of the reservoir may lead to decrease of initial oil flow rates of horizontal wells and final oil recovery factors (ORF) reduction too. It is proved that pseudohorizontal wells may incorporate advantages of vertical and horizontal wells. As a result, these wells may be more efficient in comparison with both horizontal and vertical wells.
Hydraulic Fracturing of Horizontal Wells: An Update of Design and Execution Guidelines
Authors: Lietard Olivier , Ayoub Joseph , Pearson Anthony 
Published: December 2007

Abstract
Thousands of horizontal wells have been drilled world-wide over the last ten years. Most of them are completed openhole and do not produce as well as expected. In their design phase, adverse reservoir and wellbore effects are often underestimated, such as permeability anisotropy, well stand-off, fonnation damage, formation face damage, and sand control screen plugging.
Recent statistical surveys of the production of openhole horizontal wells have confirmed that actual performances are disappointing. They are leading to major re-evaluations of drilling and completion strategies in many present reservoir developments.
In offshore environments where a limited number of slots are available, horizontal wells remain the best choice. However they are increasingly cased, cemented, perforaled and stimulated, in order to alleviate the problems affecting openhole wells.
This paper describes how this new trend is expanding in the North Sea, and gives all necessary guidelines to successfully design and execute multiple fracturing treatments in horizontal wells. Production and treatment cost estimates are provided for all cases of fracture orientation vs. the wellbore. Radial flow effects in non-collinear geometry are detailed and Tip Screen Out (TSO) designs recommended.
Olefin Sulfonates for High Temperature Steam Mobility Control: Structure - Property Correlations
Authors: Borchardt John K. , Strycker Arden R. 
Published: December 2007

Abstract
Understanding the effect of the components of commercial olefin sulfonates on steam foam performance would aid manufacturing more cost-effective products. Commercial alkene sulfonates are a mixture of alkene sulfonate, hydroxyalkane sulfonate, and olefin disulfonate. The effect of these components, hydrophobe linearity, the position of the carbon-carbon double bond in the substrate (alpha-olcfin compared to internal olefin), hydrophobe carbon number, and hydrophobe linearity on foaming properties and other properties of interest for enhanced oil recovery was studied. The connectivity index measure of chemical structures correlation with 121°C (250°F) foam stability provided a correlation coefficient of 0.98.
Chemical Dehydration: Correlations between Crude Oil, Associated Water and Demulsifier Characteristics, in Real Systems
Authors: Márquez-Silva R. L. , Key S. , Mariño J. , Guzmán C. , Buitriago S. 
Published: December 2007

Abstract
With the aim at finding a method for the selection of a suitable demulsifier for crude oil dehydration, five crude/associated water/effective demulsifier real systems were evaluated in this study. Likewise, based on the existing knowledge about the fundamentals of emulsion stabilization process, the typical characteristics of each element of the systems, which represent the variables or factors governing the process, were chosen. These variables were: in the crude oil, the acidity number, as a measure of its polarity; in the associated water, the salinity; and in the demulsifier, the relative solubility number (RSN).
A hypothesis based on the surfactant affinity difference (SAD) model is proposed. This model was adapted to the specific case of crude oil chemical demulsification. A simplified mathematical expression was obtained, which establishes a relation between the crude oil nature, the associated water salinity, and the demulsifier hydrophilicity.
The data obtained from the evaluation of the selected characteristics were introduced into the model. As a result, the following empirical relationship was obtained: lnS=-0.77A-0.28RSN+8.17
where S is the associated water salinity and A is the crude oil acidity number, variables which are easily measured.
RSN values were calculated and compared with those obtained from experiments. Except in one case, the calculated RSN value approximates very closely the experimental one. It is therefore concluded that this correlation serves to select the appropriate demulsifier to dehydrate a given crude oil, based on the simple procedure outlined above.
Testing the Corrosivity of Spent HCl/HF Acid to 22 Cr and 13 Cr Stainless Steels
Authors: Morgenthaler Lee N. , Rhodes Peter R. , Wheaton L. L. 
Published: December 2007

Abstract
Combinations of HCl and HF acids are commonly used in well stimulation in sandstone reservoirs containing substantial amounts of clay and feldspar. After reaction with reservoir minerals, the resulting spent acids arc produced through production tubing. The spent acids may be diluted with formation water and contain a variety of reaction products. Corrosion inhibitors may be depleted by adsorption on formation minerals. Laboratory tests were conducted to simulate the composition of "spent" HF-containing acids and inhibitor depletion in the formation. Test conditions were based on autoclave and coreflow experiments coupled with field data on acid flowback.
Acids containing HF remain corrosive even after extensive reaction with sandstone reservoirs. Inhibitor depletion and dilution are a significant factor in spent-acid corrosivity Field data indicate that about 80% of the injected acid is produced back diluted by about a factor of two. Guidelines have been developed for simulation of spent acid compositions with synthetic laboratory brines. Using these simulated brines, corrosion tests have been performed with 21 Cr duplex stainless steel and Super 13 Cr (SI3Cr) martensitic stainless steels in spent HCl/HF mixtures under conditions typically encountered in the deepwater Gulf of Mexico. Guidelines for acid formulation and inhibitor application have been developed.