bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reducing Electric Power Costs in Old Oil Fields
Authors: Paik M. E. 
Published: December 2007

Abstract
In older oil fields, the cost of electric power is one of the larger, if not the largest, operating cost. Field profits can be improved by focusing on oil production profits rather than oil production volumes. This requires different paradigms for managing electricity and different paradigms for field operating practices. This change in focus is essentially procedural, generating significant increases in economically recoverable reserves at minimum incremental investment.
This paper is directed primarily at the oil fields of the contiguous USA, (Lower 48 States). Conditions effecting electricity availability, usage & price differ significantly elsewhere in the world.
A New Concept for Improving Steamflood Performance in Shallow Heavy Oil Reservoirs
Authors: Sarkar A. K. , Sarathi P. S. , Strycker A. R. , Reid T. R. 
Published: December 2007

Abstract
The benefits of horizontal fractures to steamflood performance of shallow, heavy oil reservoirs are demonstrated through reservoir simulation. Two cases were considered: (1) an unpropped fracture to improve mobility of oil ahead of the steamfront, and (2) a nearly impermeable (cement-slurry-filled) fracture to improve vertical sweep efficiency. Horizontal fracturing in shallow reservoirs (&lt;1,000 ft) has been previously demonstrated.
Reservoir data for the low thickness areas of the Slocum (TX) field were used to evaluate the potential of the unpropped fracture. On initiating steamflooding, the steam was injected above formation parting pressure while the oil production rates remained high. The fracture was introduced at the top of the reservoir (i.e., away from the underlying water zone). Subsequent steam injection pressures were below the fracture reopening pressure. The results were compared to those of steamflooding where pressures were always maintained below the formation parting pressure. Steam soaking the formation with the fracture accelerated the recovery process. For the 2.5-acre pattern, project time decreased by 40%, cumulative oil steam ratio (COSR) increased by 20%, and production cost decreased by 16%. Production costs (per bbl of oil) for formations with and without underlying water zones were $13.80 and $12.30 when produced-water heat and 5-acre patterns were used.
Published data for a thick Kern River (CA) reservoir were used to evaluate the benefit of the impermeable fracture. The fracture was introduced into the reservoir, immediately below the elevation of the steam override zone, after 5.6 years of steamflooding. The steamflooding was simulated to continue in the zone below the fracture for four years, and the results were compared with those of the low-quality steamflood conducted in the field over the same period. Steamflood performance improved significantly. Oil recovery increased by 10% OOIP (30% of no-fracture production), mainly because of higher temperatures and steam saturations in the layers below the fracture.
Nature, Origin, Treatment and Control of Well-Bore Scales in an Active Steamflood, Wilmington Field, California
Authors: Davies D. K. , Vessell R. K. , Fu R. Y. , Mondragon J. J. , Stepp D. A. , Aguey O. J. 
Published: December 2007

Abstract
Three principal families of scale minerals occur in this field, carbonates, sulfates and silicates. The carbonate scale is calcite. It is chemically and mineralogically complex owing to variable substitution of Mg for Ca in the crystal lattice. Four varieties of calcite are differentiated on the basis of Mg:Ca ratios. The amount of Mg increases with decreasing temperature. Carbonate scale is precipitated at higher temperatures than sulfate and silicate scale.
Ions that form the carbonate and sulfate scales originate from formation waters. Scales that result from interactions of hot fluid with the formation (silicates) are not volumetrically significant. Long-term prevention of scale precipitation should focus on chemical treatment of fluids and reduction of well bore temperature.
Geostatistical Reservoir Characterization Using Inverted Seismic Data: Application to a Chalk Reservoir, Dan Field, Denmark
Authors: Vejbaek O.V. , Rasmussen K.B. 
Published: December 2007

Abstract
Seismic impedances calculated from logs show very good correlation to log porosities in wells penetrating the chalk reservoir in the Dan Field, Danish North Sea. This is the basis for an attempt to use seismic impedances derived from inversion as soft data for geostatistical reservoir characterization. The study focuses on porosity description of the Maastrichtian chalk reservoir unit, laterally restricted to an area covered by a subset of a 3D seismic survey. This seismic volume was inverted using the ISIS software producing a volume of seismic impedances.
Spatial porosity realisations are produced using a gaussian collocated cosimulation algorithm, where well log porosities constitute the hard data input and seismic impedances are the soft data input. The simulated volume measures 1400-1525 102 m and is oriented parallel to lines and crosslines in the seismic data set. Simulated blocks measures 25 25 6 m equivalent to twice the line and trace spacing, and approximating the seismic sample rate. The correlation coefficient between log porosities and impedances calculated from logs alone are shown to be misleading since they suggest unrealistic high coefficients. However, the inversion derived impedances and log porosities, still show correlation coefficients in the order of -0.45; sufficient to make the inversion result useful. It is remarkable that the calculated correlation coefficient is based on 15 wells, and the inversion is based on only one well. The impedances show inverse correlation to porosities. The impedance data indicate the level of average porosities at locations between wells. The fine structure is produced by the geostatistic process, with averages constrained by seismic impedances. The inversion derived seismic impedances are thus shown to constitute useful primary data to constrain reservoir characterization between wells.
Quantifying the Impact of Structural Uncertainties on Gross-Rock Volume Estimates
Authors: Samson P. , Dubrule O. , Euler N. 
Published: December 2007

Abstract
It is a common experience among geoscientists that structural uncertainties are crucial, especially when development decisions have to be taken on the basis of a small number of wells and a 3D seismic interpretation. Changes in the approach used for time-to- depth conversion and, to a lesser degree for horizon picking, may significantly impact the value of the Gross-Rock Volume (GRV). The methods presented here assume that maps of uncertainty on the time pick and on the average velocity have been produced, and they solve the problem of evaluating the impact of these uncertainty maps on GRV uncertainties.
The methods proposed consist of generating "possible" error maps that are all within the range provided by uncertainty maps. A "possible" depth map is obtained by adding an error map to the reference case. A simulated GRV can then be computed between the simulated top of the reservoir, the base of the reservoir (deduced by adding a thickness map to the simulated top, a thickness uncertainty may have been accounted for) and the Hydrocarbon-Water Contact (HWC) (its depth may have been simulated). By iterating many times (several hundreds) histograms and expectation curves of the GRV can be derived.
Introduction
The industry shows a growing interest for managing seismic uncertainties in a reservoir as they can dramatically impact the Gross-Rock Volume (GRV) estimates, especially when dealing with gently dipping structures at field appraisal stage.
Methods to simulate errors are presented as well as the use of resulting error maps (depth or time and velocity error maps) to generate "possible" depth maps. These "possible" depth maps can then be used to compute the simulated GRV. These methods are fast, and can be used to generate a great number of realisations (several hundreds) in a few hours on a workstation. Such an approach allows statistical analysis using histograms and expectation curves to derive key values such as 15%, 50% (median) and 85% quantiles.
Economic Optimization Of Liquid CO2 Fracturing
Authors: Luk Samuel , Apshkrum Mark 
Published: December 2007

Abstract
The use of liquid CO2 as a fracturing fluid has proven to be an effective stimulation for the increased production of gas in Canada and the United States. The process involves the injection of 100% liquid CO, as a proppant carrier to create a fracture and form a highly conductive channel from the wellbore into the reservoir.
The process has recently been optimized with the addition of nitrogen gas. Overall treatment costs were reduced by volumetrically replacing the more expensive liquid CO2 with gaseous nitrogen. Additional cost savings were realized with decreased power requirements due to lower liquid pumping rates and reduced friction pressures.
The results of more than seventy treatments utilizing N2/CO2 fracturing operations have been used to evaluate the limitations of this new development. The use of downhole pressure and temperature instrumentations has aided in the development of a computer simulator which evaluates the economic benefits of adding nitrogen to 100% liquid CO2. This paper will describe the computer simulator and discuss the variables in optimizing the new commingled N2/CO2 fracturing stimulation.
Coalbed Methane/Fuel Cell Operation for Direct Electric Power Generation
Authors: Haskew Tim A. , Haynes Charles D , Boyer CM , Lasseter E. L. 
Published: December 2007

Abstract
Methane released to the atmosphere during underground coal mining operations is a greenhouse gas and wastes a valuable enery resource. Coal mining in the United States released an estimated 190 to 300 billion cubic feet (Bcf) of methane into the atmosphere in 1990. Based on the current trend of increasing coal production and the mining of deeper, methane-rich coal deposits, methane emissions from coal mines have been forecast to be 260 to 450 Bcf by 2010. Because of inadequate methane capture technology, less than 5 percent of methane released during coal mining is currently recovered for use. New initiatives for coalbed methane will increase its recovery, thus providing important environmental and safety benefits while enhancing the worldwide natural gas supply. This investigation determined the feasibility for installing a 200 kW phosphoric acid fuel cell at a large underground coal mine located in the Black Warrior Basin of Alabama. Assurance of supply, variation of coalbed methane quality, and economic feasibility were studied. The fuel cell can be operated directly from variable-quality coalbed methane produced from underground mining. Waste heat from the fuel cell can be used in the mine's coal dryer, allowing a portion of the coal normally consumed in the dryer to be sold. Excess electric power, if available, can be sold to the public utility grid. An energy cost of approximately SO.05/kWh is necessary for the direct generation of electric power from a coalbed methane/fuel cell system to be competitive.
The Use of Slimhole Drilling and Monobore Completions To Reduce Development Costs at the Kuparuk River Field
Authors: Pearson C. Mark , Petrash Denise K. , Zernell Jim T. , Zanghi Mike 
Published: December 2007

SPE Members

Abstract
In 1994, a low cost development and operating plan for future wells at the Kuparuk River Field was proposed with the goal of reducing well costs 30% by the end of 1996. This paper presents this plan of a slimhole drilling and monobore completion program, a discussion of the critical issues addressed to successfully make the change, and field results from the first 16 wells drilled in 1994 and 1995.
A review of historical cost information is included which covers drilling and completing wells using the conventional well designs that had become standard in the field for the previous ten years. A variety of new slimhole well plans are presented for both production and injection wells together with a discussion of their potential application and cost savings. The paper concludes with a look at future work plans and opportunities for additional cost savings through the use of slimhole wells.

Introduction
Located in the Alaskan Arctic, the Kuparuk River Field is one of the United State's largest producing oil fields (300,000 barrels oil per day), and covers an area of approximately 115,000 acres. The field was discovered in 1969, but was not economic for development until 1977, after completion of the Trans-Alaska Pipeline. Figure 1 shows the field location on the North Slope of Alaska. Field development was started in 1979 using gravel pads as central drill sites from which deviated wells are drilled to drain a four section area (4 square miles). Initial development is on 160 acre well spacing with some 80 acre infill locations.
The Kuparuk reservoir is a sandstone at approximately 6000 feet subsea with solution gas drive as the primary production mechanism. The majority of the field is under secondary recovery receiving pressure support through a combination of waterflood and water alternating immiscible and miscible gas injection. Previous reports have documented both the geological description and the reservoir mechanisms of the field.
Production occurs from two horizons within the Kuparuk sandstone. An upper sandstone interval, referred to as the C Sand, is present over most of the southern half of the field and consists of very coarse to very fine grained siderite and sandstone. With average permeabilities of 130 md to 2600 md, and net pay ranges up to 80 ft, the C Sand typically produces at rates from 1000 to 5000 barrels per day (BPD).
The A Sand, the lower producing zone, is present throughout the field and contains 65% of recoverable oil in place.
P. 145
A Field Trial to Test Fiber Optic Sensors for Downhole Temperature and Pressure Measurements, West Coalinga Field, California
Authors: Karaman Osama S. , Kutlik Roy L. , Kluth Ed L. 
Published: December 2007

Abstract
A field trial to test fiber optic sensors for temperature and pressure measurements was completed in two temperature observation wells in a steamflood area of the West Coalinga Field in Coalinga, California. Objectives of the trial were to test a novel hydraulic deployment system that can easily install and retrieve fiber optic sensors from wellbores and to test the data quality from a fiber optic Distributed Temperature Sensor (DTS) and a pressure sensor.
Deployment of the temperature and pressure fiber optic sensors was successfully demonstrated by using the hydraulic deployment technique. Excellent data correlation was obtained between the DTS and the conventional wireline conveyed temperature survey tools. Similarly, the pressure sensor showed impressive resolution and dynamic response capabilities. Since the fiber optic system has the capability of providing continuous reservoir temperature and pressure data, reservoir management in primary or assisted recovery projects can be improved.

Introduction
The objectives of this field trial were threefold:first test a hydraulic deployment system whereby a thin fiber optic cable can be deployed and retrieved easily.test a Distributed Temperature Sensor (DTS) for data quality and reliability of obtaining temperature profiles in a high temperature environment.test a fiber optic pressure sensor in a high temperature environment.
The pressure sensor, which was simultaneously deployed with the temperature sensor in a closed system, was tested by applying pressure from the surface. The performance of both systems proved very effective and provided high quality data in a high temperature environment.
The field trial took place in the West Coalinga Field. The Field is located on the west side of the San Joaquin Valley approximately 100 miles northwest of Bakersfield, California. Field production is primarily heavy crude (12 to 15 API) from the Miocene Temblor Formation. The target reservoir consists of two sand layers separated by a shaly layer. The sands are unconsolidated with an average porosity in excess of 30%, an original oil saturation ranging from 45% to 55%, and an average air permeability of approximately 800 millidarcies horizontally. The upper sand layer averages 45 ft. in thickness, while the lower sand is about 35 ft. thick.
Steam injection in this reservoir was initiated in October 1988 and is ongoing today. Production from the constituent reservoir sand layers is enhanced by steam injection through a single tubing string. Permeability variations between the two sand layers resulted in uneven processing over major portions of the field. Since steam injection costs are the highest of all operating costs, it is critical to manage heat distribution in the reservoir properly.
P. 351
Improved Recovery of Light / Medium Heavy Oils in Heterogeneous Reservoirs Using Air Injection / Insitu Combustion (ISC)
Authors: Greaves M. , Wilson A. , Al-Honi M. , Lockett A.D. 
Published: December 2007

Improved Recovery of Light / Medium Heavy Oils in Heterogeneous Reservoirs Using Air Injection / Insitu Combustion (ISC).

Abstract.
A one-quarter of a 5-spot physical model was used to carry out a series of low pressure air injection / insitu combustion (ISC) tests on light and medium heavy crude oils, to investigate the effect of reservoir heterogeneity on oil recovery.
It was found that a horizontal producer well does not act as a high permeability streak, but actually increases and brings forward production.
Extensive work on the construction and saturation of an artificial consolidated porous media was successfully undertaken and is now ready for further combustion experiments.

Introduction.
The demand for oil world-wide is rising at about 1-2% a year. This, combined with the increasing difficulty of finding new large reservoirs has put pressure on major consuming countries, especially in mature field areas such as N. America and the UK Continental Shelf (North Sea), to develop new recovery techniques, i.e. improved oil recovery (IOR) - Gregory, 1995.
When the reservoir energy is great enough (initially), the oil will normally flow to the producing well and up to the surface without any additional pumping. This is called primary recovery.
When the natural energy becomes too low the well needs to be pumped or injected with water or gas to displace more oil. The latter is called secondary recovery.
Waterflood is a secondary recovery method and is used extensively to increase recovery up to 50% of the original oil in place (OOIP).
Oil is left in a reservoir after waterflooding for two principal reasons: -Some oil remains in parts of the reservoir that have not been adequately swept by water. This inefficient sweep can be caused by viscous fingering, - Peters et al, 1987, (pronounced in both light and heavy oil reservoirs), but also by adverse heterogeneity and channelling effects in the reservoir. Significant oil, at high saturations, may also be trapped beneath shale layers, which are difficult to locate precisely.In the regions that have been frilly swept, oil is trapped in the form of droplets, or ganglia in the pores of the rock by capillary forces.
Clearly, with at least 50% of OOIP still remaining in the reservoir, increased attention needs to be focused on ways of increasing the recovery. Improved oil recovery techniques (IOR), especially enhanced oil recovery (EOR) processes such as air injection (low temperature oxidation and in-situ combustion - high temperature oxidation) need to be investigated.
The principle of insitu combustion is to burn part of the oil (or fuel fraction, i.e. coke), to mobilise the remaining oil. Combustion is started by an ignition device, or by spontaneous ignition, which raises the zone surrounding an injection well to a significantly high temperature, so that continued injection of air or oxygen containing gas causes the combustion to self propagate. P. 435
HSE Training and Competence Assessment in the Geophysical Industry
Authors: Covil M. W. , Soethout Joost A. , Reynolds Gerry , Carouso Mark , Jeffers Stuart 
Published: December 2007

Abstract
This paper looks at the efforts of the seismic geophysical industry to continually improve it's health, safety and environmental performance, and in particular to improve the HSE behaviour and understanding of individuals within the industry. Specifically it deals with Ihc HSE training and assessment of competence of individuals in relation to their job responsibilities, based on best industry practice
Human Factors in E & P Facility Design, a Participatory Approach
Authors: Dekker G. F. , van den Bergen E. A. 
Published: December 2007

Abstract
To ensure that ergonomics are taken into account in the conceptual design phases of engineering projects, NAM has introduced the "Ergonomics in design" workshop. This paper describes the general format, timing and techniques used in these workshops. An example of a case study is presented together with a cost benefit analysis. Finally, a concluding summary of the workshop success factors is given together with the areas for further improvement.
Environmental Assessment on Alaska's North Slope
Authors: Herlugson C. J. , Parnell J. A. 
Published: December 2007

Abstract
Since oil production began at Prudhoe Bay, Alaska, in 1977, numerous monitoring programs have examined the region’s biota in an effort to establish baseline conditions and support impact assessments. These programs are used to reduce or mitigate changes resulting from oil and gas development. North Slope exploration and production operations are governed by a complex set of regulations that often require monitoring. Monitoring programs are conducted annually to measure air emissions, water quality, and the distribution and abundance of wildlife within the operating areas.
Environment, Health & Safety Management Systems for Upstream Oil & Gas Projects in Developing Countries
Authors: Gossen R. G. , Mann G. J. 
Published: December 2007

Abstract
The international oil and gas exploration and production industry faces a vast array of environmental issues that are global in nature but play an increasingly prominent role in individual project decision making. When placed against a backdrop of socio-political and cultural challenges presented in developing countries, project planners require an enlightened approach to ensure the environmental, economic and social components are appropriately balanced to ensure sustainable business success. Although a relatively new player in the international E & P industry, Canadian Occidental Petroleum Ltd. has developed such an approach to EH&S management for projects in developing countries. Drawing from recent experience with a major project in Yemen, and others in the planning stages in several other developing countries, this paper presents a number of positive strategies and actions which are being applied in the many countries in which the company is active. Lessons learned and opportunities for improvement are presented for consideration by responsible operators working internationally toward the goal of environmentally sustainable energy development.
Organized For Safety
Authors: McCleary Michael D. , Schuberth Paul C. , Hining Dennis E. 
Published: December 2007

Abstract
The Exxon Company, International Drilling Organization (ECIDO) is committed to an injury-free workplace through continuous efforts by identifying and eliminating or managing safety risks associated with drilling activities. The newly developed and recently completed ECIDO Safety Management Program (SMP) strengthens this commitment by defining a comprehensive, management approved, organized framework for drill teams from which operations safety is managed both effectively and consistently worldwide. The SMP is proactive, focuses on positive recognition, promotes greater individual involvement, and gives part ow nership of the safety program at the rig level to the crews.