bluuebunny/crossref_metadata_2025_split huggingface dataset:
Benefits of Performing an Acoustical/Mechanical Study on a Four-Unit Compression Installation
Authors: Vevurka J. W. , Fifer Frank 
Published: December 2007

Abstract
Every reciprocating compressor transmits pulsations into the piping system. These pulsations may or may not result in problems such as high vibrations, poor performance, or measurement error. Given that pulsations are inherent in reciprocating compressor installations there are basically two approaches from a pulsation/vibration point of view to installing a reciprocating compressor package: Design and build the package with very little conscience consideration given to potential pulsation and vibration problems. At start-up try to fix any problems that occur.Have an acoustical/mechanical study performed and implement the necessary modifications prior to fabricating the package.
This paper discusses the benefits of performing an acoustical/mechanical study on a reciprocating compressor installation. Recently such a study was completed between Arkansas Western Gas Company (Owner), PAMCO (Equipment packager) and Beta Machinery Analysis Ltd. (Engineering company who performed the study). Predicted As Found versus Final Modification pulsations and unbalanced forces are presented.
Pulsation control, whether it be via a simple volume bottle or a bottle designed with internals, is required for most reciprocating compressor installations. There are capital and operating costs associated with these pulsation control devises. Performing an acoustical analysis enables these devices to be designed to optimize the pulsation control, capital cost and operating cost (pressure drop) over the range of operating conditions expected during the life of the compressor. Excessive pulsations can directly effect compressor performance and indirectly have an adverse effect on the piping system. Some of the concerns, all of which have associated cost, are: Lower volumetric efficiency leading to decrease in capacity.Higher valve losses resulting in increased brake horse-power/MMSCFD.Pulsation induced valve vibration leading to possible failures.Increased rod loading sufficient to cause rod failures.Pulsation induced cyclic rod loading transmitted to the compressor crankshaft as dynamic torque and excited torsional shaft vibrations, which may lead to possible failure.Acoustical response coincident with torque mechanical natural frequency, which may cause rod failure and possible crankshaft failure.
Uncontrolled pulsation will, in the long run, cost money. This will be spent in the repair of worn and failed parts or downtime (lost revenue) and increased fuel consumption of the compressor unit.
Viscous Property Measurement of Delayed Titanate Crosslinked Gels Containing Oxidative Breakers
Authors: Craig D. P. , Fan Yong , Holditch S. A. 
Published: December 2007

Abstract
Since 1983, the Gas Research Institute (GRI) has funded research to improve the knowledge and understanding of the viscous properties of fracturing fluids. One of the GRI research projects was the development and testing of the GRI Rheology Unit, which is a mobile rheology laboratory that can be taken to the field to measure the viscous properties of the actual fluids being pumped during the treatment.1–2
The GRI Rheology Unit consists of a van containing two Fann Model 50 viscometers and a complete wet chemistry laboratory. In typical field operations before the treatment begins, the Rheology Unit is used to check the fracturing fluids for contaminants and to verify the fracturing fluid, mixed with the chemicals to be used during the treatment, meet the design specifications. During the treatment, the Rheology Unit is used to sample and test the fluids being pumped to ensure fracture fluid quality.
Field research with the GRI Rheology Unit has found that laboratory measured fracturing fluid properties are often not reproduced under field conditions.1–2 During the majority of treatments monitored with the GRI Rheology Unit, fluid problems were diagnosed by testing the gel using the Fann Model 50 viscometers. One of the most common fluid problems experienced in field operations is the scheduling and addition of the chemical breakers used to degrade the fracturing fluid after the treatment. Typical problems associated with the breakers were either (1) the wrong breaker type was being used or (2) the wrong amount of breaker was added for the given conditions.
Fracture Identification from Well Logs
Authors: Iverson W. P. 
Published: December 2007

ABSTRACT
The Silo oil field in southeastern Wyoming produces oil from the fractured Niobrara chalk. Chalk has very little matrix permeability and produces best from areas where, the chalk contains pervasive open fractures. This fractured reservoir is examined with five physically independent fracture characterization techniques; oriented micro-resistivity logs, borehole elongations, sonic logs, nuclear logs, and vertical seismic profiles. In this reservoir, at this location, the oriented micro-resistivity logs give the best overall identification of fractured intervals, probably because the most productive fractures are open and fluid filled. Borehole elongations, commonly called breakouts, also correlate with fractured intervals. Fractures are found both parallel and perpendicular to borehole breakouts. Sonic waveform attenuation also correlates with fractured intervals, although no orientation information is provided by the sonic log or the other nuclear porosity logs. The M-N nuclear-sonic logging technique is shown to work only for one well in this area, yet the response is due entirely to density log anomalies. A second M-N plot from Silo shows no indication of fractures while the well produced oil from fractured chalk. The final fracture identification technique shown in this paper is the vertical seismic profile. Shear waves are polarized into fast and slow directions due to anisotropy of the fractured chalk.
Well Performance Evidence for Compartimented Geometry of Oil and Gas Reservoirs
Authors: Junkin J. E. , Sippel M. A. , Collins R. E. , Lord M. E. 
Published: December 2007

ABSTRACT
Well pressure and production histories and transient pressure tests, evaluated by conventional well testing techniques and simulation, are shown to indicate compartmented reservoir geometry arising by depositional and diagenetic processes. Examples are cited of both clastic and carbonate reservoirs but the central focus of this study is on fluvial deposits exhibiting stratigraphic compartmentation. Field examples of compartmented behavior in such reservoirs are demonstrated by wells with spacing corresponding to separations as small as 1/4 mile. Furthermore, directly drained compartments with radii as small as 60 feet are demonstrated. The impact of such compartmentation on development strategies is examined.
Application of Matchstick Geometry To Stress Dependent Permeability in Coals
Authors: Seidle J. P. , Jeansonne M. W. , Erickson D. J. 
Published: December 2007

Abstract
Several investigators have reported coal permeability decreases with increasing stress, but no conceptual model has been advanced to explain this effect. To better understand the permeability of stressed coal, a theoretical and experimental program was undertaken. A common naturally fractured reservoir geometry, a collection of matchsticks, was extended to stressed coalbeds and tested against laboratory measurements using samples from the San Juan and Warrior Basins. Good agreement was obtained between theoretical behavior and laboratory data. Equations are presented for converting laboratory measured stress-permeability data to (a) in-situ permeability as a function of depth of burial in a basin, and (b) to reservoir permeability during coalbed depletion.
Coal cleat compressibility, analogous to pore volume compressibility of conventional reservoirs, has historically been difficult and expensive to measure and the results of such measurements are often ambiguous. A method is presented for calculating cleat volume compressibility from stress permeability experiments, resulting in considerable savings of both time and money. Stress-permeability and cleat volume compressibility results reported here are compared with those published in the literature.
Evidence in the literature indicates that coal matrix shrinks when gas is desorbed, increasing cleat permeability. Assuming a matchstick geometry and using a coal matrix shrinkage coefficient reported in the literature, the increase in cleat permeability due to matrix shrinkage was calculated. The increase in permeability due to matrix shrinkage during depletion is compared with the decrease in permeability due to increased stress.
Microfracture Stress Tests, Anelastic Strain Recovery, and Differential Strain Analysis Assist in Bakken Shale Horizontal Drilling Program
Authors: Kuhlman R. D. , Perez J. I. , Claiborne E. B. 
Published: December 2007

ABSTRACT
The economical completion of the Bakken Shale often dictates the drilling of a horizontal wellbore. A horizontal wellbore placed through a naturally fractured shale formation introduces drilling problems of wellbore collapse, the opening of existing natural fractures, or creation of fractures. Knowledge of magnitude and direction of the in-situ stresses is important in determining the optimum direction to drill a horizontal wellbore. The stress direction is important because a horizontal wellbore has its maximum stability when it is in the direction of minimum principal in-sttu stress. Combining the in-sttu stress magnitude data from microfracture stress tests, the in-sttu stress direction from anelastic strain recovery and differential strain analysis, and mechanical properties from laboratory tests, one can determine the minimum and maximum allowable drilling mud weights and optimize wellbore direction if necessary.1
The microfracture stress test was used to determine stress magnitude. Successfully performing the microfracture tests has meant overcoming problems inherent in performing these tests at high temperatures and high injection pressures associated with deeper wells in addition to concerns with the naturally fractured shale's stability. Some special equipment was required for the tests. Special surface injection equipment, developed in recent years was used to perform the tests. Standard downhole drillstem testing tools were deemed to be the most appropriate and were used in a special configuration to isolate the zones of interest and to overcome some of the problems associated with temperature and pressure (increasing depth), the natural fractures, and problems with borehole sloughing.
Problems peculiar to naturally fractured shale affected the anelastic strain recovery (ASR) and differential strain analysis (DSA) testing.
This paper presents a systematic approach for determining in-sttu stress field direction and magnitude and applying these measurements to determining the minimum and maximum limits of mud weight and wellbore direction for optimum drilling design in the Bakken Shale.
Constant Curvature Method for Planning a 3-D Directional Well
Authors: Guo Boyun , Miska Stefan , Lee R. L. 
Published: December 2007

ABSTRACT
A new method for planning 3-D directional wellpaths is proposed in this paper. This method, which is referred to as the Constant-Curvature Method, has several advantages over the conventional Radius-of-Curvature Method and Constant-Turn-Rate Method. The new method yields constant curvature wellpath sections which are compatible with the directional performance of deflection tools. In addition to this advantage, this method also yields less dogleg severity of well trajectories, and, consequently, less drag and torque on the drill string. As a result, it is expected that the directional drilling operation should be easier, safer, and more economical if the wellpaths are planned using the proposed method. Mathematically, the formulation of the method involves integrals that do not have closed form solutions and need to be estimated numerically. To avoid the numerical integrations, two alternative approximations to the exact solution, namely Piecewise-Radius-of-Curvature Method and Piecewise-Constant-Turn-Rate Method, are presented. Sample computations show that the Piecewise-Constant-Turn-Rate Method gives better approximations and the calculations can be carried out using a hand-held calculator.
The Use Of Fluid-Loss Additives In Hydraulic Fracturing Of Oil And Gas Wells
Authors: Hawsey Jerry D. , Jacocks Claude L. 
Published: December 2007

Abstract
The theory of low fluid-loss hydraulic fracturing as a means of stimulation to oil and gas wells is presented. The fluid-loss properties of current fracturing fluids are shown by a demonstration of the API testing method. Fluid-loss test results are interpreted in comparing fracturing fluids.

Introduction
The method of fracturing to be discussed is not new. It is a process introduced to the oil industry in 1955 and was used sparingly at the outset, but has experienced tremendous growth in the past three years.
The discussion will be divided into three parts. 1. Presentation of the theory of low fluid-loss fracturing. 2. Demonstration of the fluid-loss properties of current fracturing fluids. 3. Interpretation of fluid-loss test results in comparing fracturing fluids.

HISTORY OF FRACTURING FLUIDS
First, a brief discussion of the history of fracturing fluids. Fracturing began in 1949 with the initial fracturing fluids consisting of viscous fuel oils, gelled kerosene or napalm. During the next five years, little change took place in the nature of fracturing fluids. The first major change occurred in 1954 with the advent of low fluid-loss additives. Prior to this time, it was believed that viscosity was necessary to prevent sand outs; however, this was soon disproved by the use of fluid-loss additives in lease crude. Fracturing methods changed tremendously during the years following 1954, and in 1957 Howard and Fast presented a paper covering the mathematical treatment of the factors controlling fracture extension. Present-day fracture calculations are based largely on this work. Today, with economical and efficient fracturing fluids, many jobs utilizing an excess of 100,000 gal of fracturing fluids are being performed. In fact, a major oil company in 1959 fractured a well in South Texas in one stage using 180,000 gal of lease crude and put away 270,000 lb of sand with the aid of a low fluid-loss additive. The use of low fluid-loss additives has more than quadrupled in the last six years, and in 1960 over 125 million gal of fluid with low fluid-loss additives were pumped.

THEORY OF LOB FLUID-LOSS FRACTURING
First, the mechanics of fracture extension as illustrated in Fig. 1 should be investigated. The left portion of this figure shows the result of using high fluid-loss fracturing fluids.
Nimr Medium Radius Horizontal Learning Curve
Authors: Perry B. D. , Ali I. H. , Vancura J. 
Published: December 2007

ABSTRACT
In January 1991, Petroleum Development Oman L.L.C. began a campaign to drill six medium radius horizontal wells in the Nimr field in South Oman. The wells were drilled with a 12-1/4" build up section followed by an 8-1/2" horizontal section. On the basis of this campaign, a decision was made to extend the number of horizontal wells to be drilled in the Nimr field during 1991. The first three wells of the second campaign were drilled to the same design as the original six wells, principally due to the non availability of certain tubulars needed for a radical design change. Once the required equipment was available, the wells were drilled and completed with a Composite Liner Design, i.e. the build up and horizontal sections were drilled and cased in the same hole size.
This paper discusses the original well design criteria, the results of the operational learning curve (the new design concept for Nimr wells), and the economic benefits. By the end of February 1992, four of the new design wells had been successfully drilled and completed.
Vibration Of Oil Well Cement
Authors: Skalle P. , Sveen J. , Justnes H. 
Published: December 2007

ABSTRACT
Gas leakage through cement in the annular space around a cemented casing is still a serious problem, although new additives and methods have reduced the problem. The problem is related to migration through the cement matrix itself or to migration along the cement's Interfaces with the casing and the formation, caused by poor displacement of mud and/or loss of hydrostatic pressure within the cement slurry during curing.
One solution to this problem Is to transmit vibrations to the cement through the casing. The objective of vibration of oil well cement is to counteract the continuous reduction of hydrostatic pressure and to maintain low permeability during hydration of cement. The hydrostatic pressure within the slurry must be higher than the pressure within the gas bearing formation. Vibration tests in a two meter high cement column have resulted in guide lines as to what frequency, amplitude, vibration Intervals and duration should be selected to maintain column pressure. For similar vibration parameters it has also been investigated if the short (1 day) and long term (7 days) strength of the cement has been negatively influenced. Different methods for practical implementation of oil well vibrations have also been considered.
Through vibration of oil well cement, not only the cement will become more gas tight, but also the physical bond between cement/casing and the strength of the cement itself will be considerably improved.
An Integrated Approach To The Recognition and Characterisation Of A Fractured Limestone Reservoir In The Ilam Formation, Fateh Field, Dubai – U.A.E.
Authors: Wood J. R. , East G. R. 
Published: December 2007

ABSTRACT
Reservoir Engineering and Geological data gathered from 22 years of production from the Fateh Ilam reservoir and from almost 200 wells cannot be reconciled using existing reservoir and geological models. Prior to building a full field model to evaluate further development of the waterflood and potential for future infill drilling, a better understanding of the reservoir is required.
Recent re-characterisation of the reservoir is described and results are summarized from a fully integrated reservoir study that showed the Ilam to be both complex and heterogeneous. Examination of the core and log data revealed orientable fractures that, following detailed analysis, were seen to be crudely related to lithology. The study also shows that the wide range of pressure transient characteristics and anomalous production and waterflood behavior observed in the Ilam can be explained using a simplified model consistent with these findings.
Geochemical Study of Crude Oils and Source Rocks in Onshore Abu Dhabi
Authors: Lijmbach G. W. M. , Toxopeus J. M. A. Buiskool , Rodenburg T. , Hermans L. J. P. C. M. 
Published: December 2007

ABSTRACT
The Petroleum geochemistry of Abu Dhabi onshore has been studied. From cutting and core analyses the presence of five main source rock intervals could be established in the Middle Cretaceous Shilaif Formation, the Lower Cretaceous Shuaiba Formation and Bab Member, the Upper Jurassic Dukhan Formation, the Upper Triassic Minjur Formation and the Permian Khuft Formation. Analyses of 13 crude oils resulted into five oil families. The Simsima reservoired oil of the Shah field appeared to originate from the Shilaif Formation source rock, while the Shuaiba oil of the Shah field is sourced from a shaly Bab Member source rock. The Kharaib reservoired oils in the Asab, Bu Hasa, Rumaitha, Sahil and Jam Yaphour fields originate most probably Irom Bab Member source rocks, while the Qatar and Habshan reservoired oils of the Bu Hasa and Shah field are likely to be related to Dukhan source rocks. For the Habshan oils of the Shah field, investigated in this study no matching source rock could be identified yet. Finally a maturity modelling study for the main source rock bearing Stratigraphie intervals was carried out.
Multi-Well Data-Base: An Example Of Field Applications
Authors: El Hadidi S. , Dajani F. , Reiss A. , Plomb J-P. 
Published: December 2007

ABSTRACT
Data-bases have become a topical subject in the oil industry. In the absence of any previous experience in this domain by oil field personnel, the tendency is either, to try and invent the wheel, or to borrow ideas from other industries with database experience. Either of these courses could be very expensive and could lead to a cul-de-sac.
The ADNOC Data-base in Abu Dhabi is probably the most advanced petrophysical multi-well database (MWDB) in the oil business. After five years of dedicated data-base work by a team of specialists, with all the data of approximately 2200 wells that represents over 7 million feet of open hole loaded, a wealth of experience and expertize was developed to write professionally on the subject of data-base applications in the oil industry.
This paper presents a case study of a data-base application for a large field. The paper discusses the organization and input of all types of well and field data, data quality control, normalization of all the data for field consistency and homogeneity, and the field and multi-well concept of data interpretation and estimation of missing data. The paper discusses in detail the applications of the data-base for reservoir simulation and for Stratigraphie and structural studies of the various formations and layers in a field. The emphasis here is that a data-base is not just an instrument of data storage and retrieval, but is an effective way to manage the reservoir.
One of the main conclusions made was that an effective data-base can be used to efficiently utilize human resources so that an engineer can spend 10% of his time sorting and searching for data and the remaining 90% doing effective analysis. In the absence of an effective data-base, the tendency is reversed; 90% sorting and searching and 10% of analytical work.
Brine Deterioration Of Cement And A Replacement Cementing Technique
Authors: LaFleur K.K. , Lovelace W.P. 
Published: December 2007

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
Field studies of wells on the Nesson Anticline in North Dakota have shown that cement placed during original primary cementing operations in many of the wells has now deteriorated to the point that zone isolation no longer exists. In their present condition, they cannot be stimulated or used successfully as injection wells. Squeeze cementing has proved highly uneconomical because many repeated stages are required. Even with repeated stages, success ratios have been extremely low. This paper describes a replacement cementing-technique developed to remove deteriorated cement and replace it with new cement. While developed for Nesson Anticline wells, the technique should prove successful in other areas where similar problems exist. problems exist

Introduction
Many of the wells producing front the Madison formation along the Nesson Anticline in North Dakota had declined as early as 1963 to a point where they would no longer produce their allowable. Some stimulation was started at that time. In 1966, however, North Dakota allowables were raised, and a great number of the wells were treated with large volumes of acid to increase the production. The majority of these wells treated on vacuum. Little or no increase in oil production resulted from the treatment, although there was often a large increase in water production. Wells which required surface pressure to displace the acid showed good increases in oil production.
It was suspected that channels existed in the primary cement in the wells which treated on vacuum and that the acid was not entering the desired producing zone. The wells which treated with pressure were believed to have the primary cement intact. Acid was confined to the desired zone and reservoir penetration with the acid provided good production increases.