bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Through-Tubing Junction-Isolation System Enables High-Pressure Stimulation in the Ekofisk X-02 North Sea Multilateral Well: Case History
Authors: Steele David J. , Edholm Steinar 
Published: December 2007

Abstract
Phillips Petroleum Company, Norway (PPCoN) operates the Ekofisk and Eldfisk Fields in the North Sea. In an effort to increase production while reducing well costs in these fields, the operator implemented a plan to drill three multilateral wells. The maturing Ekofisk and Eldfisk Fields produce from multiple chalk reservoirs with natural fractures. Drilling horizontal wellbores to intersect the natural fractures within chalk reservoirs has proven to be very successful throughout the world (i.e. North Sea and the Austin Chalk Trend in Texas). Thus, by drilling three multilateral wells, Phillips would not only be able to intersect the reservoirs targeted but also would be able to save three platform slots and reduce the expense of drilling and completing three horizontal wells.
Although this project involved completions of three wells, this paper will focus on the third well, the Phillip’s Ekofisk X-02, which was the most successful because of the lessons learned and applied from the first two completions. The primary changes made in the completion design and operational strategies in the third well relate to junction integrity and the use of a state-of-the-art Straddle Stimulation Tool (SST) to isolate the lateral junction during performance of a high-pressure acid-fracturing operation on the upper lateral. The SST is designed to eliminate complications sometimes encountered with traditional upper lateral stimulations such as when drill stem test (DST) tools or plugs do not inflate or retrieve properly. Additionally, this through-tubing, junction-isolating stimulation tool is less costly and safer to use because the stimulation is conducted after the completion equipment and production tree have been installed.
Comparing the results of the X-02 completion with the first two will illustrate that the capability to perform a high-pressure acid-fracture stimulation (versus a acid-wash stimulation) can increase production and eliminate the risks and costs of running a DST-type acid-fracturing procedure. In addition, since the completion string and production tree can be installed before perforating and stimulating the well, safety is increased, and future well costs can be reduced since the lateral can be re-stimulated without pulling the production string.
Foinaven 4D Seismic - Dynamic Reservoir Parameters and Reservoir Management
Authors: O'Donovan A. R. , Smith S. G. , Kristiansen Pal 
Published: December 2007

Abstract
4D seismic data acquired across a segment of the Foinaven field have been combined with Petrophysical data and reservoir simulation. The resulting integrated, multi-disciplinary approach places 4D seismic data firmly in the arena of reservoir management. As a result of this successful application across a segment of Foinaven, 4D seismic data will be acquired on an annual basis across the two producing fields in the West of Shetland area of the UKCS and contributes significantly to reservoir management.
Strategies for Optimal Enhanced Recovery of Heavy Oil by Thermal Methods, Midway-Sunset Field, Southern San Joaquin Basin, California
Authors: Schamel Steven , Deo Milind 
Published: December 2007

Abstract
A previously idle portion of the Midway-Sunset field, Aera Energy's Pru Fee property, has been brought back into commercial production through tight integration of geologic characterization, geostatistical modeling, reservoir simulation, and petroleum engineering. This property, shut-in over a decade ago as economically marginal using conventional cyclic steaming methods, has a 200–300 foot thick oil column in the Monarch Sand. However, the sand lacks effective steam barriers and has a thick water-saturation zone above the oil-water contact. These factors require an innovative approach to steam flood production design that balances optimal total oil production against economically viable steam-oil ratios and production rates. The methods used in this DOE Class III oil technology demonstration are accessible to most operators in the Midway-Sunset field and could be used to revitalize properties with declining production of heavy oils throughout the region.
The production strategy adopted in the steam flood pilot is to restrict steam injection to the upper one-third of the pay zone, that portion where oil saturations exceed 50%. Any steam injected below this interval would loose large quantities of heat to water and result in unfavorable steam-oil and water-oil ratios. During the fourth year of the oil demonstration project, production from the 8 ac four-pattern steam flood pilot continued to remain high. As of December 1999, the oil rate was averaging 308 BOPD and the cummulative oil production from the pilot alone was 335 MBO. The steam-oil and water-oil ratios, measures of steam flood effectiveness, closed the year at about 5 and 8, respectively. Also, an additional 37 new wells drilled in 1998 surrounding the pilot have been put into cyclic production. By the end of 1999 they were producing up to 458.3 BOPD, bringing the total oil rate for the Pru Fee property up to 689.0 BOPD. The total production from the property since the beginning of the project in late 1995 is 541.0 MBO. The average production rates per well are higher under steam flood than in cyclic mode.
Analytical Solution of Dynamic Inflow Performance
Authors: Asheim H. 
Published: December 2007

Abstract
Due to the compressibility of reservoir fluids and matrix, production wells posess dynamic properties. Analytical solution are developed for inflow performance, when bottom well pressure is subjected to combinations of oscillations and excursions. The formulae provided predict the dynamic productivity index, as function of rock and fluid properties, oscillation frequency and attenuation factor. The dynamic inflow performance provides proper bottom well boundary condition for stability analyses of gas-lifted wells.
Effect Of Underground Waters In Localizing Oil Accumulations
Authors: Dickey Parke A. 
Published: December 2007

Oil and gas are fluids but our prospecting methods have been based mainly on observations of the reservoir rocks. Little use has been made of measurements of the physical and chemical properties of their fluid contents.
There is now general agreement that petroleum originates in a very disperse state and is segregated into oil pools during the compaction and lithification of the sediments. The mechanism of this process is little understood, but it may be caused by the expulsion of pore water from the sediments and involve a capillary filtering action. If the routes of water migration and the location of capillary filters could be predicted, much more use could be made of our available geological data in predicting likely places for oil to accumulate.
Usually the oil remains where it was originally trapped. Sometimes, however, the regional dip may be reversed and the oil will then run to the other end of the aquifer that contains it. In mountainous areas, reservoirs are severely disturbed and often breached so the oil can run out, which is the principal cause of surface oil seeps. In such areas an effort should be made to locate the sites of the original accumulations, and then consider where the oil might now be.
Field Study - Ford Geraldine (Delaware Sand) Unit
Authors: Meyers Brent D. , Hagler James A. 
Published: December 2007

Abstract
This paper presents a case history of the Ford Geraldine (Delaware Sand) Unit waterflood operation located in Culberson and Reeves Counties, Texas. The Unit, operated by Continental oil Company, is presently under waterflood in the Delaware presently under waterflood in the Delaware Sand. Presented is a discussion of injection pattern selection, injection well interval pattern selection, injection well interval control and monitoring, injected water quality control and, finally, use of reservoir models in prediction and performance matching.
Extensive water injection well work has been performed consisting of running injection profiles on most wells and remedial jobs on wells with poor injection distribution to alter injection profiles and improve vertical sweep efficiency. Injected water quality control is unique in that Pecos River water is used, which necessitates oxygen and bacteria treating in addition to the removal of solids by filtration. Three computer reservoir simulation model studies have been run to match performance, to date, and to assist in selection of infill well locations.
Specifically, the significance of the Ford Geraldine (Delaware Sand) Unit waterflood is that it is one of the very few successful waterfloods in the Delaware Sand. Field data, lab data, and computer modeling work will be presented in the discussion.

Introduction
The Geraldine-Ford Field is located in extreme northern Reeves and northeastern Culberson Counties, Texas. Refer to Fig. 1. Development began with the discovery by Ford Chapman, of the G. E. Ramsey No. 1, in April 1956, and has continued to date. Production from the Geraldine-Ford Field is from the Bell Canyon Formation of the Delaware Mountain Group at an average depth of 2680 feet. There are two producing Bell Canyon Sand members in this reservoir. The Ramsey, or upper, Zone is the principal producing sand body and the Olds, or lower, Zone has been found to have productive potential throughout a large portion of the potential throughout a large portion of the field. The Ramsey Zone is considered the better waterflood prospect due to its greater areal extent and more favorable porosity, permeability, and oil porosity, permeability, and oil saturation.
Well Logs and 3D Seismic Data Integration Using Geostatistical Methods, Lomas del Cuy Field–Golfo San Jorge Basin–Argentina
Authors: Atencio Mario , Sánchez Victor , Breda Eduardo , Fronza Silvana , Saavedra Benito , Hansen Tomas , Souza Jorge 
Published: December 2007

Abstract
The Estancia San Justo Norte Area in the Lomas del Cuy Field was characterized using geostatistical methods. The distributions and thickness of sand bodies were determined within an area of over 20 square km, with 42 drilled wells, and 3D seismic interpreted by REPSOL-YPF.
The intervals of interest were determined from well logs, correlated throughout the field and related with the 3D seismic data. The appropriate reflectors were identified in the seismic, and time windows were established so that these would match the selected intervals. A total of seven windows was used and within each of them 25 seismic attributes was extracted. On the other side, petrophysical evaluations were made from well logs obtaining results for gross, net and net pay thickness and average petrophysical properties within the intervals.
Good correlations were found between petrophysical properties and certain seismic attributes in 6 of the 7 windows. In these cases, cokriging was used to map the petrophysical properties integrating the seismic data. As a result, petrophysical maps guided by seismic attributes were obtained for net thickness, net/gross, net porosity thickness and average net porosity. These maps proved very useful for determining new well locations.
The results clearly indicate that the application of this technique is very effective for describing the fluvial type reservoirs with small lateral continuity, typical of the Golfo San Jorge Basin. Geostatistical methods were good predictors of sand body distributions in each of the analyzed intervals.
This data is extremely valuable in the development of fields when it is integrated with the rest of the available information in the area.
Fluid Design Considerations for Deep Hot Wells
Authors: Barrett N.D. , Joyce V.A. , Free Dustin 
Published: December 2007

Abstract
Greater depths mean increased temperatures and usually mean increased pressures. These two parameters have dictated changes in the way hydraulic fracturing treatments are designed and performed.
The purpose of this paper is to describe current fracturing fluids and to discuss their advantages, shortcomings and applications. A singular, ideal frac fluid does not exist since requirements will vary with the formation, well conditions, fracture design, economics and stimulation goals. However, basic principles can be staged as a guide to a more optimum fluid for high temperature requirements.

Introduction
The search for energy has led to deeper and deeper drilling. Where just a decade ago a 10,000-ft. well and its associated temperature stretched the limits of our treatment fluid technology, it is now commonplace to design and perform hydraulic fracturing treatments at depths below 15,000 feet. Successful fracture acidizing treatments have been performed in wells whose depth exceeds 24,000 feet. Temperature at these depths ranges from 250 degrees F to 400 degrees F in the Anadarko Basin.
Bottom-hole static temperatures of wells in the Anadarko Basin can usually be defined by a temperature gradient of 1.0 to 1.2 degrees Fahrenheight per 100 feet of depth. This is the area in which the authors are most familiar. Using this temperature gradient criteria, a 16,000-ft. Morrow formation well drilled in an area having a 1.1 degrees F/100 feet gradient will have a BHST of 250 degrees F.
Electric logs are relied upon to measure the temperature of each individual well.

FLUID DESCRIPTIONS

1. Water Gels
Water gels can be easily mixed by batchor continuous mix processes with goodreliability and can be made temperaturestable. Surface pressures are less than with other fluids. This results from high hydrostatic heat and friction pressures that are only 25% to 35% offriction pressure of water alone.
Advanced Dual Probe Formation Tester with Transient, Harmonic, and Pulsed Time-Delay Testing Methods Determines Permeability, Skin, and Anisotropy
Authors: Proett Mark A. , Chin Wilson C. , Mandal Batakrishna 
Published: December 2007

Abstract
Three new pressure-transient testing methods are employed to determine horizontal and vertical permeability using a dual probe formation tester. Real-time interpretation during acquisition of pressure data, is the focus of all three new pressure-testing techniques. In the first, a new spherical flow model with anisotropy, storage, and skin is developed from first principles for dual probe analysis. Historically, pressure transient solutions are presented as Laplace transforms and approximated in the time domain using numerical techniques. Typically, early, intermediate and late time periods are identified using derivative plots; but very often, the selection of appropriate data results in confusion. Here, the Laplace transform is inverted to yield a single, exact, closed form, analytical, time domain solution valid for all times, making real-time parameter matching possible with high accuracy.
The second technique uses an oscillatory displacement source at the piston face, and the phase delay of the pressure pulse between the probes is used to determine permeability and anisotropic index. This technique is particularly useful when the second monitoring probe signal is weak (as in high permeability zones) or where there is large spacing between the probes. Pulse timing can usually be detected more accurately than its magnitude, thus extending the range of permeability and anisotropic measurements. This methodology, which is based on a derived relationship between wave phase and permeability, was developed by mathematical analogy with resistivity determination methods used in induction logging.
In the above method, it is often possible to encounter "phase wrapping" for excessively tight formations, leaving an indeterminate permeability. To circumvent this problem, in the third method, a short, abrupt "pulse" having a well-defined "center frequency" is produced at the piston face, and its travel time is measured until arrival at the receiver probes. The harmonic, closed form expression is then used to translate this travel time to permeability. This new method is analogous to sonic wave models; although, of course, "waveforms" are often smeared due to the diffusive nature of the problem.
Simulation results using a detailed finite element, dual probe model are compared against the above analytical methods to assess the effects of near wellbore parameters such as mudcake effectiveness, probe, and packer size. Field-test results are shown to demonstrate the successful implementation of these new testing methods. The three methods described above provide a practical level of redundancy in permeability prediction. Also, monitoring permeability and anisotropy changes while sampling are shown to be beneficial in identifying fluid type changes.
Theory and Application of Well Analysis
Authors: Morgan Rodney , McKee Fount E. 
Published: December 2007

FUNDAMENTALS OF WELL ANALYSIS
A well analysis program is an area where any oil company can make money immediately. It appears that most well analyses are performed by large oil companies that have large computer facilities. However, in order to use these facilities, a great deal of effort is required on the part of the engineer or technician. Quite often, the engineer could make a few calculations with a small calculator and have the answer to the problem. This requires that the engineer understand the basic principles of the pump, rod string, and pumping unit operation
Equipment to obtain the necessary data has been hard to use and required considerable time. Usually, the pumping system had severe problems before the time and effort would be spent to analyze it. Now, equipment is available that will allow the engineer or technician to obtain the data easily and make an analysis in a few minutes.
Of primary importance is a thorough understanding of the operation of a modern oil well pump. Fig. 1 is a schematic drawing of such a pump.
There are three main components of an oil well pump: the standing valve (SV), the traveling valve (TV), and the pump barrel. The SV is located in the bottom of the pump barrel and opens or closes, depending on the relationship between the Pressure Pl and P3. The TV is located in the plunger and opens or closes, depending on the relationship of the Pressures P2 and P3. Pressures P2 and P3.The operation of the pump is as follows. Assume that the pump plunger is at its lowest point and is starting to move upward. As the point and is starting to move upward. As the pump plunger stops and begins to move upward, pump plunger stops and begins to move upward, the TV closes because Pressure P2 is the same as Pressure P3, and the weight of the TV causes it to fall into its seat. With the TV closed and moving upward, Pressure P3 is reduced. When the pressure difference between Pl and P3 is large enough, the SV will be forced open. This allows well fluid to flow into the pump barrel. As the plunger rises, the pump barrel continues to fill. Note that the reason for the pump barrel filling was the plunger moving upward, which reduced Pressure P3. When the plunger stops its upward movement at its plunger stops its upward movement at its topmost position, Pressures Pl and P3 equalize and the SV closes because of its own weight. When the plunger, starts down, it will be forced into the fluid in the pump barrel, which will cause Pressure P3 to increase above Pressure P2, thus opening the TV. P2, thus opening the TV.
The Tangguh LNG Gas Fields: Conceptual Development Overview
Authors: Kasim Achmadi T. , Titus Iwan , Roberts J. Wayne , Bulling Tom P. 
Published: December 2007

Abstract
Recent exploration, appraisal and certification activities have established certified proved gas reserves in excess of 14 trillion standard cubic feet (TCF), and potential reserves of 24 TCF, for the fields already identified in Berau Bay, Irian Jaya, Indonesia1. The project to develop this gas resource has been named Tangguh LNG. This project encompasses production and processing of natural gas to manufacture liquefied natural gas (LNG) plus storage, loading and shipping for markets in the Asia-Pacific region. The goal of Tangguh LNG is to create a positive, progressive development with mutual benefit to business and the community in which it is operated – and which does no harm to the environment. This paper describes some of the conceptual upstream development planning that has been carried out in support of the Tangguh LNG project.
The conceptual development planning is based on the data from an extensive drilling and seismic campaign that was conducted to establish the magnitude of the gas reserves found mostly offshore in six fields, including the giant Wiriagar Deep and Vorwata gas fields. The resultant integrated dataset contains substantial log, core, pressure, drill stem test and seismic information and was the basis for the reservoir and fluid descriptions used in models for conceptual planning.
Both analytical and numerical simulation models have been used for conceptual development planning. Single well analytical models have mainly addressed well deliverability. Simulation models have been used to investigate the interaction of several major reservoirs in the six gas fields, an aquifer, and a surface network supplying gas to the LNG plant. Pipeline simulation models have been used to investigate the possible use of multiphase pipelines to supply gas to the plant, thereby simplifying the offshore facility design.
For conceptual development planning, the scope of initial development for the Tangguh LNG project has been designed for a two train LNG plant with an average sales volume of 6 MTPA. Highly prolific wells, a large reserve base, and an uncomplicated offshore development setting result in an efficient, low cost, and highly reliable LNG project for this design basis.
Measurement of Residual Gas Saturation in Water-Driven Gas Reservoirs: Comparison of Various Core Analysis Techniques
Authors: Mulyadi H. , Amin R. , Kennaird T. , Bakker G. , Palmer I. , Van Nispen D. 
Published: December 2007

Abstract
The objective of this study was to derive values of residual gas saturation (Sgr) for water-driven gas reservoirs using various core analysis methods: steady-state waterflood, co-current imbibition, centrifuge and counter-current imbibition. The relative dearth of published data comparing various core analysis methods, and the uncertainty in estimating Sgr for gas reservoirs under water-drive, resulted in the decision to attempt to determine an optimum laboratory protocol to evaluate Sgr.
Core samples from various reservoirs, representing a range of porosity and permeability values, were selected for testing. The various analyses were conducted to represent a range of field displacement mechanisms where viscous, capillary or gravity forces may dominate.