bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analyzing a Multi-Lateral Well Failure in the East Wilmington Field of California
Authors: Brister A. Ray 
Published: December 2007

Introduction
As the industry pursues optimum cost drilling techniques, more focus is being applied to multi-lateral technology. The presently available literature invariably focuses on the cost and efficiency benefits of drilling multi-lateral wells. What is missing in the media, however, are the benefits associated with publication of the negative aspects or costly failures of higher-technology multiple-lateral projects that require a mechanical tie-back or pressure seal at the junction of the laterals (i.e. Class 3 or 4 type multi-lateral wells, respectively). This paper is a case study of a Class 4 multilateral well attempted by Thums Long Beach Company in the East Wilmington Field of California. To date, this case study represents the only detailed analysis of an unsuccessful attempt to drill a Class 4 multi-lateral well. Starting with a field and well profile, this case study explores Well B743A in the Long Beach Unit of the East Wilmington Field of California. The discussion progresses from the original proposal through the drilling and completion of the lower lateral to the drilling of the upper lateral, and then to the plugging and abandonment both laterals. Finally, the analysis provides an examination of six critical problem areas encountered during the drilling of Well B743A: hole cleaning, cementing and junction stability, whipstock orientation, tubular size, re-entry, and risk management. These are areas that are problematic for most operators and contractors struggling with multi-lateral technology, especially the drilling of Class 3 or Class 4 multi-lateral wells.

Field and Well Profile
The Long Beach Unit of the East Wilmington Oil Field is located just offshore at the southwestern extension of the Los Angeles Basin of California (Fig. 1).
The field produces from three major zones, the Ranger, Terminal, and Union Pacific-Ford zones (Fig. 2). Individual sand units are continuous and can be correlated over the Long Beach Unit and beyond. The structural setting is an asymmetrical northwest to southeasterly trending, faulted anticline.
P. 169^
New Analytic Techniques for Petroleum Fluid Characterization Using Molar Refraction
Authors: Touba Hassan , Mansoori G. Ali , Sarem Amir M. Sam 
Published: December 2007

Abstract
Molar refraction of pure hydrocarbons, petroleum fractions, and other compounds present in petroleum are shown to represent well the asymmetry of such fluids. Molar refraction is used to correlate density, parachor, and other properties of hydrocarbons with an accuracy that was not achieved before. Various calculations are made to demonstrate the accuracy of the proposed new analytic techniques for various reservoir fluids characterizing properties. Molar refraction characterizes the pure as well as the complex hydrocarbon mixtures and can be measured directly and accurately. It is shown that molar refraction is a more appropriate property to correlate the asymmetry of hydrocarbon fractions than the other existing methods. Plenty of the molar refraction data have been reported in the API Data Book for all the hydrocarbons and non-hydrocarbon compounds making it possible to extend the applicability of the proposed technique to high molecular weight ranges.

Introduction
The molar refraction which can be measured in the laboratory is a direct measure of the London dispersion forces which affect the PVT behavior of pure fluids and mixtures. The molar refraction, R, is defined by the following equation: (1)
where n is the index of refraction and v is the molar volume. The molar refraction of a substance can also be expressed in terms of the polarizability by using Clausius-Mosotti equation.
(2)
where N0 is the Avogadro number and is the polarizability. If a substance has a permanent dipole moment, then the polarizability is the sum of two terms:
(3)
where 0 is the distortion polarizability related to the displacement of the electronic cloud of a molecule with no permanent dipole moment in an electrical field and is the orientation polarizability which arises from the tendency of the permanent dipole moment to be oriented in the direction of the applied field. The orientation polarizability, , is related to the dipole moment and is inversely proportional to the absolute temperature.
(4)
In this equation, k is Boltzmann constant and T is the absolute temperature.
Substituting Eqns. (3) and (4) into Eq. (2), we get the following equation for the molar refraction.
(5)
We may assume methane as a reference substance for which the dipole moment is zero (= 0), and obtain the molar refraction of other substances with respect to methane.
P. 507^
Large Scale Application of Acid Stimulation - Tulare Zone, South Belridge Field, Kern County California
Authors: Dean Gregory D. , Giunta Rick L. , Baggs Donald T. 
Published: December 2007

Abstract
Extreme near well-bore acid stimulations have successfully helped to maintain production in the Tulare Zone of the South Belridge Field. An economical alternative to redrilling wells was a driving force behind this program. Since 1991 over 600 of these treatments have been performed while monitoring and employing quality improvements and system optimization. After the initial successful treatments were performed, the following treatments were continuously monitored and databased. Due to the lack of a good statistical number of wells, many early attempts at optimizing the treatments were tried with little engineering justification. Subsequently, these attempts fell short of truly optimizing the treatments. In 1993 a full scale engineering study was implemented to help understand the mechanism for success. The study included the construction of a slotted liner acidizing test apparatus, detailed analysis of the crude, core analysis, and construction of a treatment database. Details of the study are shown in the paper along with the resulting three year production data.

Reservoir Geology
The South Belridge Field is located in the southwestern San Joaquin Valley, about 40 miles west of Bakersfield, CA. The northwest to southeast trending anticline structure stretches nearly 9 miles across the San Joaquin Valley Floor and is just under 2 miles across at the widest point. Structural dip is approximately 4 degrees to the southwest. Production occurs from several different horizons which vary in continuity across the field. The reservoirs range in geologic age from Miocene to Pleistocene. The trap dimensions are controlled by both the overall structure and stratigraphy of the individual sand bodies. The Tulare can be divided into several flow units separated by clay boundaries. These are the Upper Tulare (Zones A, B, and C) and the Lower Tulare (Zones D and E). Acid stimulation treatments detailed in this study were all performed in the Pleistocene Tulare formation in sections 3 and 4 which are located in the southern portion of the field. The stimulation program occurred over a 3 year period from 1993 to 1995 and consisted of over 550 acid treatments.

Reservoir Description
The Tulare is a heavy oil reservoir with unconsolidated, loose and grain supported sands. Reservoir properties are listed in Table 1. Primary production occurred in the Tulare from 1917 to 1963 at which time steamflooding was introduced. Steamflooding today is still the primary method of enhanced recovery in the South Belridge Field. Peak production of 50,000 BOPD was achieved in 1995 from over 600 wells.

Well Description
Wells are typically completed on 5 acre spacing. All of the wells stimulated are completed with an openhole gravel pack and 16–30 or 12–20 mesh sand. P. 619^
Field Test of Produced Water Treatment With Polymer Modified Bentonite
Authors: Doyle D.H. , Brown A.B. 
Published: December 2007

Abstract
The combination of ET Ventures' ET #1 and granular activated carbon consistently and effectively removed hydrocarbons from Tensleep formation produced water in a 24-hour test at Teapot Dome oil field. Specific findings are that ET #1:–Reduced Total Petroleum Hydrocarbon (EPA Method 418.1) to non-detectable levels.–Reduced Oil and Grease (EPA Method 413.2) to non-detectable levels.–Reduced soluble hydrocarbons: Benzene, Ethylbenzene Toluene, and Xylene (BTEX-EPA method 8020) to barely detectable levels.
BTEX was below detectable limits after the combination of ET #1 and granular activated carbon.

Introduction
This report describes the results of a test conducted at the Rocky Mountain Oilfield Testing Center (RMOTC) of a product manufactured and marketed by ET Ventures, L.L.C. This product, ET #1, is designed to adsorb hydrocarbons from wastewater. The test conducted at RMOTC was intended to document the ability of ET #1 to:–Adsorb a relatively large quantity of hydrocarbons from oilfield produced waters carrying a free oil sheen.–Tolerate the wide variations in hydrocarbon concentrations typical of oilfield operations.–Adsorb soluble hydrocarbons in the BTEX family under these same circumstances.
A 24-hour test was designed in which produced water from the Tensleep formation was flowed through a three-stage treatment system composed of two stages containing ET #1 and a final polishing stage containing granular activated carbon (GAC).

Product Description
ET #1 is a product generally referred to as a polymer modified bentonite or an organoclay. This group of materials is manufactured by binding an amine polymer onto bentonite clay and drying it in a granular form. The polymer binds to the bentonite's ionic surfaces and converts the clay from a hydratable form to an oil-wet, hydrocarbon adsorbent material. Other clays are also used for the manufacture of organoclay, depending on the application and location of mineral deposits.
Organoclay is commonly used in the upstream sector of the petroleum industry for removing hydrocarbons from refinery process water, but it has seen little use in petroleum production. Many other industries also use it, including shipping and dockside servicing, carwashes, and others dealing with an oily wastewater stream.
Organoclays have also been tested for treating ground and surface water for other organic chemicals such as PCBs and pesticides.
Present and Future Constraints on Oilfield Produced Water. Oilfield produced water is an important source of surface water in the arid western U.S. The discharge of produced water is permitted under the National Pollutant Discharge Elimination System (NPDES), which may be administered by the U.S. E.P.A. or by a state program. In addition, other state and federal programs come into play to generally prohibit the presence of a free oil sheen or staining of the shoreline of surface impoundments. Netting may also be required over surface impoundments in order to protect migratory birds from hydrocarbon contamination.
P. 137^
Current Practices in the Tip Screenout Fracturing of High Permeability Reservoirs in the Gulf of Mexico
Authors: Morales R.H. , Norman W.D. , Price P.A. , Stewart B.R. , Works-Minter A.M. , Ali Syed A. 
Published: December 2007

Abstract
This paper summarizes practical experiences gained in several aspects related to the tip screenout fracturing of high permeability formations in the Gulf of Mexico (GOM). In particular the paper discusses current practices related to the:evaluation of mechanical properties of the reservoir;selection of the fluid and proppant;design and analysis of the calibration treatment;design of the main fracturing treatment;placement of the treatment;post fracturing analysis, andperforation of the reservoir.
P. 147
Six Months in the Arctic
Authors: Wassel Gordon C. 
Published: December 2007

Abstract
This paper will present a brief outline and description of the Gas Arctic Systems Study Group's program in the Alaska and Canadian Arctic. Gas Arctic Systems is proposing a 48-inch gas pipeline from Prudhoe Bay, Alaska through a portion of Alaska, into Canadian Yukon territories, Northwest territories, and Alberta Province where the line would connect to existing Alberta Gas Trunk Line facilities to the Canadian-U. S. border or other Canadian pipeline facilities. A project of this magnitude requires extensive-research and planning before implementation.

Introduction
For about two years, Northern Natural Gas Company has been a member of a consortium of six major U. S. and Canadian companies. This consortium, consisting of four U. S. companies: Northern Natural Gas Company; Texas Eastern Transmission Corporation; Columbia Gas Systems, Inc.; Pacific Lighting; and two Canadian companies, Alberta Gas Trunk Line; Canadian National Railway Company; is actively studying and developing a gas pipeline project to bring Alaska and Northern Canadian Gas to markets in project to bring Alaska and Northern Canadian Gas to markets in Canada and the lower 48 states. These activities have resulted in the formation of the Gas Arctic Systems Study Group who have undertaken development, research and feasibility studies resulting in expenditures of seven million dollars in 1971, with a similar level of studies planned for 1972.
Operating Curves for Single and Multistage Reciprocating Compressor
Authors: Sparta David P. , Kuss Ronald H. 
Published: December 2007

Abstract
This paper discusses a computer program that develops operating curves for single and multi-stage reciprocating compressors. The operating curves, which show horsepower requirements as a function of pressure, are used as an aid in operating compressors.
The series-parallel flow of the gas in a staged unit sets up interrelationships between the stages and also between the cylinders of each stage. At constant horsepower, small suction pressure changes cause large changes in the discharge pressure. The interrelationships and the suction pressure sensitivity cause convergence problems in modeling staged compressors. The convergence problem becomes more pronounced as the number of stages increases.
The first part of the paper discusses a technique that solves the convergence problems in modeling staged units. The technique is discussed along with the results of a computer program written to test the modeling techniques. program written to test the modeling techniques. The second part of the paper discusses how this test model is built into a production computer program that develops and plots operating curves. This program automatically produces the curves using the compressor's data (bore, stroke, clearance, etc.)

Text
Northern Natural Gas Co. uses operating curves as an aid in operating reciprocating compressors. These curves show horsepower and volume as a function of suction and discharge pressure for a given cylinder clearance; a pressure for a given cylinder clearance; a separate plot is used each clearance configuration. Figs. 1 and 2 show typical curves for single and multistage compressors. The operating curves are generated by a compressor model.
There are convergence problems in modeling staged compressors. Fig. 3 is a schematic of a typical staged unit. The series-parallel flow of the gas sets up interrelationships between the stages and also between the cylinders of each stage. The flow distribution, for example, to a stage's cylinders may change with pressure because of different clearances. As noted in Fig. 2, small suction pressure changes at constant horsepower cause large changes in the discharge pressure. The interrelationships and pressure sensitivity cause convergence problems pressure sensitivity cause convergence problems in modeling staged compressors.
A modeling technique was developed and tested that solves the convergence problem. An ideal compressor handling an ideal gas is assumed in describing this model. The actual test model used modified equations that compensate for real compressor and gas behavior, such as compressibility, valve leakage, etc.
A Modified Muskat Analysis of a Reservoir Containing Fluids with Composition Dependent Properties
Authors: Rowe A. M. , Comer A. G. 
Published: December 2007

Abstract
A new method is presented that can be used to predict molal specific volumes of equilibrium states as a function of reduced pressure. The reduced pressure for pressure. The reduced pressure for multicomponent systems, in turn, is defined as the ratio of the operating pressure divided by the convergence pressure as determined by the Critical Composition Method. This technique essentially extends the law of corresponding states to include multicomponent systems that exist in a two-phase region of phase space. Published experimental data is used to justify Published experimental data is used to justify this extension.
This method was first programmed into a phase routine to determine how accurately it phase routine to determine how accurately it would predict experimentally determined liquid saturations obtained by constant volume expansion of a volatile reservoir fluid. Experimental and predicted results were found to be in very close agreement.
After this approach was verified, this technique was then incorporated into a Modified Muskat analysis to predict recovery from a volatile oil reservoir.

Introduction
The U.S. is currently faced with an energy shortage that has resulted in deep-well exploratory drilling (in excess of 30,000 ft.). At these greater depths, reservoirs are more likely to contain volatile fluids since the reservoir pressure and temperature are higher than normally encountered at more shallow depths. Therefore, due to the nature of these fluids, the ability to calculate reservoir performance and thus predict recoverable performance and thus predict recoverable reserves will require the accurate determination of their phase compositions and accurate predictions of the densities of equilibrium liquid predictions of the densities of equilibrium liquid and vapor phases. The phase composition calculation is based on mass conservation, while an accurate phase-density calculation is necessary for the conservation of pore volume.
This paper presents a method for predicting volatile oil recovery that incorporates predicting volatile oil recovery that incorporates both of these conservation principles by utilizing the thermodynamic properties correlated as a function of convergence pressure, temperature, and pressure. One of the potential advantages of such an approach lies in applications to non-equilibrium displacement of a liquid by a gas phase.
Changing Wellbore Storage Effects In Gas Well Testing
Authors: Al-Haddad S. , LeFlore M. , Lacy T. 
Published: December 2007

Abstract
Extended wellbore storage can be mistakenly interpreted as a reservoir response in gas well testing with surface shut-in. This interpretation usually results in false values for permeability, skin and reservoir size and shape.
This paper investigates gas cooling effects on pressure transient testing with surface shut-in in gas wells. This study was prompted by the observation, that in gas wells, many of the buildup tests obtained with surface shut-in exhibited complex reservoir model behavior with relatively low skin. These models, such as narrow channels or multiple nearby boundaries, often did not agree with the actual reservoir system thus resulting in incorrect estimations of well and reservoir parameters. This in turn may result in missed opportunities to enhance well productivity and to develop the field further.
The results presented in this paper are based on well test simulation and field data from five wells in three different fields offshore Louisiana. This work demonstrates the effect of gas cooling. in combination with gas compression. on the pressure derivative curve. Knowledge of the expected pressure derivative shape. and duration, will improve the design of buildup tests that will allow enough time for the actual reservoir response to be observed. This will result in a reliable reservoir model and correct estimation of permeability and skin factor.

Introduction
To minimize cost and operational risk, many well tests are performed with a surface shut-in with a bottom-hole pressure measurement, rather than bottom-hole shut-in and pressure measurement. However, a surface shut-in includes many factors that can effect the bottom-hole pressure value. The combined effect of these factors is usually referred to as the wellbore storage effect and period. A surface shut-in allows fluid flow from the tested formation into the wellbore for a long period of time, depending on the permeability and thickness of the formation, and the wellbore volume. Moreover, the multiphase composition of wellbore fluids results in an upward movement of the gas phase relative to the liquid phase. These changes in fluid pressure and temperature, may also result in liquid drop out or evaporation (phase changes). These factors will result in significant changes in the wellbore fluids' compressibility, density, and composition.
Lee presented procedures to design well tests including after-flow conditions. He used Agarwal, Al-Hussainy, Ramey type curve empirical fit which predict the end of wellbore storage duration. In terms of equivalent shut-in times, Ate, the duration of after-flow is given by the following equation:
Hegeman, Hallford, and Joseph presented a model for analyzing increasing or decreasing wellbore storage. Their model is based on modification and extension of Fair's approach. Fair modified Van Everdingen and Hurst equation by adding a term to account for the pressure change caused by phase redistribution:
The changing storage pressure function has the following properties:
(2a)
(2b)
(2c)
P. 77^
Formation Testing While Underbalanced Drilling
Authors: Kardolus C. B. , van Kruijsdijk C. P. J. W. 
Published: December 2007

Abstract
Underbalanced drilling is more and more considered an option for the drilling of low-pressured reservoirs and a method to prevent formation damage, especially in the case of horizontal wells. The production rate during drilling depends on reservoir characteristics and the degree of undcrbalancc. As such it carries similar information as a pressure transient test. However, the boundary conditions for this particular situation are distinctly more complex. Underbalanced drilling results in boundary conditions which vary with time. Measurements of these boundary conditions downhole would make it possible to de-couple the wellbore physics from the formation. The significance of such measurements can be shown by simulating the formation response to the time-varying boundary conditions. In order to do this, a (semi-)analytical model has been developed. The model describes the dynamic process of producing while lengthening the wellbore. It connects pressure with rate of penetration and can be used to predict production rates as a result. In addition we developed an analytical procedure that allows direct interpretation of the rate data, yielding estimates of reservoir parameters. A Boundary Element Model (BEM) has been developed to model the rate transient response for time varying well parameters (underbalanced drilling).
Natural Gas Supply and Demand Problems
Authors: Hatamian H. 
Published: December 2007

Abstract
World natural gas consumption quadrupled over the 30 years from 1966 to 1996, and today it provides 22% of the total world energy demand. The security of natural gas supply is paramount and rests with the suppliers and the consumers. This paper gives an overview of world natural gas supply and demand and examines the main supply problems. The most important non predictable variables in natural gas supply are the current world-wide gas price and the current political stability, particularly in regions with high reserves. Other important considerations are the cost of development / processing and transport of the natural gas to the market: this itself can be difficult to maintain confidence if pipelines pass through areas of political instability. Another problem is that many countries lack the infrastructure and the capital needs for the effective development of their natural gas industry. Unlike oil, the cost of transportation of natural gas is very high and at present surprisingly only about 16% of the total world production is traded internationally.