bluuebunny/crossref_metadata_2025_split huggingface dataset:
Powder River Basin Coalbed Methane Wells—Reserves and Rates
Authors: Swindell Gary S. 
Published: December 2007

Abstract
Coalbed methane has become a significant source of U.S. natural gas production, contributing 9% of the country's supply and 10% of its proved reserves. The most active coalbed methane area is the Powder River basin of eastern Wyoming, with more than 20,000 wells completed in the last 10 years with annual additions of greater than 2,000 wells.
This study analyzed the projected ultimate recovery, flow rates and dewatering time of 6,600 wells producing from the Wyodak and Big George coal zones – the source of 58% of the basin's cumulative production, 61% of the current production and 45% of the CBM wells.
For the Big George and Wyodak wells, the estimated ultimate recovery (EUR) averages 223 million cubic feet (MMcf) per well (median 168 MMcf). An average peak gas rate of 319 thousand cubic feet per day (Mcf/D) (median 236 Mcf/D) occurred an average of 1.2 years after the well was placed on production. The average well declined at a rate of 45% per year after entering the decline phase with very little hyperbolic behavior (average b = .09). Distributions of EUR and peak rates were strongly log-normal.
The EUR and peak gas rates both show a slight overall deterioration over time, although the "spread" is larger with more high rate wells in later years. But the time to reach peak gas rate is shortening as more areas are dewatered.
There seems to be only a slight correlation between total depth and EUR and little correlation between gross perforated interval and estimated ultimate recovery or peak rate, although the perforated interval information is very incomplete.
Development of Powder River basin coalbed methane has an average finding cost of $.71/Mcf, and the mean well has a return-on-investment of 4.70:1 and a net present value index of 3.74, assuming a base gas price of $6.50/Mcf minus $1.50/Mcf for market differential and transportation.
Hydraflow: Avoiding Gas Hydrate Problems
Authors: Haghighi H. , Azarinezhad R. , Chapoy A. , Anderson R. , Tohidi B. 
Published: December 2007

Abstract
Flow Assurance continues to remain a major challenge in offshore production operations. Current methods for avoiding gas hydrate problems are generally based on one or a combination of the following three techniques: (1) injection of thermodynamic inhibitors (e.g. methanol, ethylene glycol) to prevent hydrate formation, (2) use of kinetic hydrate inhibitors (KHIs) to sufficiently delay hydrate nucleation/growth, and (3) maintaining pipeline operating conditions outside the hydrate stability zone by insulation and/or active heating and/or by controlling pressure.1 However, for many production operations, particularly deepwater fields, those requiring long tiebacks, and mature reservoirs (where water cuts can be very high), the above techniques may not be economical and/or logistically practical. Thus the industry needs novel and improved techniques to tackle flow assurance problems for such challenging conditions. The new approach presented in this paper –HYDRAFLOW– aims to meet this need.
HYDRAFLOW is a novel ‘cold flow’ concept, which breaks from the tradition of straightforward hydrate prevention. Instead, gas hydrate formation in pipelines is intentionally induced and managed, eliminating the need for expensive thermal/chemical inhibition while improving the economics and practicalities of multiphase fluid transport.
Experimental analyses of low and high GOR systems for various different production scenarios with and without AA (Anti-agglomerant) have been undertaken as part of HYDRAFLOW concept development. The effect of simulated shut-in on fluid transportability has also been tested. A new experimental set-up for measuring the viscosity of the fluid system under high-pressure conditions has been designed and commissioned in order to evaluate the rheology of the systems under investigation.
Results prove that the concept is viable (at least under laboratory conditions), and strongly suggest that HYDRAFLOW technology could offer significant benefits over existing flow assurance strategies, providing a novel low CAPEX/OPEX solution for challenging (e.g. deepwater, long tie-backs, mature fields) operations.
Massive Hydraulic Fracturing Unlocks Deep Tight Gas Reserves in India
Authors: Shaoul Josef , Ross Michael , Spitzer Winston , Wheaton Stuart , Mayland Paul , Singh Arvinder Paul 
Published: December 2007

Abstract
Tight gas fracturing was pioneered in North America in the 1970's and 1980's, and also has a relatively long history in Germany. In the rest of the world, however, massive fracturing for production from tight gas formations (i.e. k &lt; 0.1 mD) has been very rare, due mainly to poor economics, rather than lack of opportunities. A massive oil field was recently discovered in Rajasthan (northwest India). The field development would require significant amounts of natural gas for heating and processing of the waxy oil to be produced. The most economical solution to provide sufficient gas in this remote desert location was to produce it from a deeper formation discovered in the same area. The majority of the gas is contained in a volcanic section of basalts and felsics. A fracturing campaign was performed in 2006 on three deep gas wells to evaluate the post-stimulation production increase from a number of different horizons, with base formation permeabilities varying from 0.005 to 0.15 mD.
A comprehensive program of core testing, fluids compatibility testing and pre-fracture diagnostic injections was performed. Fracture stimulation treatments were performed in three different sections of this very thick gas-bearing formation (&gt; 400 m gross height). The formations ranged from the highest permeability (0.15 mD) Fatehgarh sandstones, to a lower permeability Felsic section (0.05 mD) and the lowest permeability volcanic rock (0.005 mD). All three types of rock were stimulated successfully and post-fracture well testing showed initial production rates agreeing with what was expected based on reservoir simulation. This important result supports the proposition that unconventional gas resources in Asian countries can be attractive when stimulation techniques perfected in other areas (i.e. North America) are applied1.
Identifying, Correcting, and Allocating Geodetic Systems to Georeferenced Data in Hydrocarbon Exploration by Using High-Resolution Satellite Imagery
Authors: Alvarez Gabriel 
Published: December 2007

Abstract
Introduction
Hydrocarbon exploration in Argentina started long before the IGM created a single, high-precision geodetic reference network for the whole country.
For that reason, several geodetic surveys were conducted in every producing basin, which have ever since then supported land surveys, well placement, seismic programs, etc.
Currently, every basin has a huge amount of information referenced to the so-called "local" geodetic systems, such as Aguaray in the Northwestern Basin, 25 de Mayo in the Cuyo Basin, Quiñi-Huao in the Neuquén Basin, Pampa del Castillo in the San Jorge Basin, and Tapi Aike in the Austral Basin, which differ to a greater or lesser extent from the national Campo Inchauspe datum established by the IGM in 1969 as the official geodetic network.
However, technology development over the last few years and the expansion of satellite positioning systems such as GPS resulted in a new world geodetic order.
Argentina rapidly joined this new geodetic order through the implementation of a new national geodetic system by the IGM, i.e. the so-called POSGAR network (Fig. 1), which replaced the old national Campo Inchauspe system. However, this only helped to worsen the data georeferencing issue for oil companies, as a third reference system was added to each basin. Now every basin has a local system, the national system in force until 1997 (Campo Inchauspe), and finally the newly created POSGAR network national satellite system, which is geocentric unlike the former two planimetric datums.
A Bayesian Production Analysis Technique for Multistage Hydraulically Fractured Wells
Authors: Vega Leonardo 
Published: December 2007

Abstract
Wells in tight gas reservoirs are often completed with multiple stages of hydraulic fracturing. Eventually, each stage contributes to the commingled well production.
This paper presents a stochastic analytic production analysis technique for multistage hydraulically fractured wells*. Based on Bayes's theorem, the new technique integrates production performance data, production logs, and prior information to arrive at the most probable description of the reservoir/completions.
After validating results with a numerical reservoir simulator, we systematically used the new technique to investigate the effect of data availability, i.e. the number of production logs and duration of production period, on the accuracy of the results.
Technical Integrity Assurance of Unmanned Wellhead Platforms for Safe Well SIMOPS
Authors: Ciaraldi Stephen , Utama Satria , Dewi Natalie S. , Sulistyorini R. , Lubis M. Syafei 
Published: December 2007

Abstract
BP West Java offshore operations include over 140 unmanned wellhead platforms which are frequently the sites of infill drilling and workovers using jack-up rigs. Although operational SIMOPS controls have been systematic for years, only recently has attention been directed towards the technical integrity of the platforms themselves. Most of the unmanned facilities are over twenty years old and of variable condition. Potentially severe consequences could result from a platform hydrocarbon leak during SIMOPS, made worse by the high density of drilling personnel working on site and in the rig offices and accommodations.
For this reason, a program was instituted to assure the technical integrity of unmanned wellhead platforms as a prerequisite for well SIMOPS. The work program includes thorough inspections of platform hydrocarbon pressure systems, including attached risers, as well secondary structures such as gratings, hand-rails and stairs, process safety protective and other critical electrical and instrument systems. When necessary, time consuming repairs must be executed before SIMOPS, but in some cases, mitigations are sufficient based on a risk-based rationale. The program has been a considerable challenge to implement due to the hectic pace of well operations, but has certainly reduced major accident risks associated with SIMOP activities and therefore resulted in a safer work environment.
Radial Drilling in Argentina
Authors: Bruni M. , Biasotti H. , Salomone G. 
Published: December 2007

With a world context of high oil prices and a rate of increase in reserves from new discoveries, that is not enough to compensate the rate of extraction, in addition to the high maturity of oilfields currently being developed in Argentina, companies have been working to improve the recovery factor of reserves, as a strategy to extend the useful life of the existing assets.
Working in this direction, radial drilling technology seems to be an alternative, which, in spite of the fact that it currently raises uncertainty since it has never been tested in the past in or country, can be adapted to the existing wells thus becoming a low investment alternative.
The technology involves drilling lateral horizontal bores of small diameter and up to one hundred meters long, with the possibility of placing several within the each productive layer. The laterals are made in two steps: First, the casing is perforated with a ¾" mill and then the lateral extension is carried out by high pressure water jetting.
For this evaluation, pilot tests were performed in different oilfields, with the intention of covering a wide range of possible scenarios and being able to evaluate the best applications for this new alternative.
The selected scenarios and the different basins are the following:

Golfo San Jorge Basin:
Mature Oilfields: already exploited formations with production below the economic limit. Viscous Oils: Formations with high viscosity oil and low mobility.

Neuquén Basin:
Mature Oilfields: low production formations Precuyano Formation (altered ignimbrites) of low permeability, with possible micro-fissures to improve net production. Water Injection: To increase secondary recovery improving the sweeping of the formation.
This work shows the different experiences undergone by Repsol YPF in Argentina with this technology as well as shares the results obtained and the lessons learned.
Biostimulation Treatments of Hydrocarbon-Contaminated Soil in Semiarid Patagonia, Argentina
Authors: Haro P. A. , Perez J. D. , Alvarez A. F. , Silva R. A. , Alvarez H. M. 
Published: December 2007

Abstract
Bioremediation is considered an appropriate technology for decontamination of polluted natural environments. The successful application of bioremediation depends on appropriate hydrocarbon-degrading microorganisms and environmental conditions in situ. Las Heras is a place located in northwest Santa Cruz (Patagonia, Argentina) with a very intensive activity of oil industry. In this region the conditions most likely to limit hydrocarbon degradation include cold and fluctuating temperatures, low moisture contents, low nutrient levels and alkaline pH. In this work we describe three representative cases of biostimulation treatments (nutrients and water addition) applied to soils with different pollution states: Case A (1680 m3) exhibited high values of total petroleum hydrocarbons (TPH 33510 mg/kg); Case B (480 m3) showed high values of total petroleum hydrocarbons (TPH 27754 mg/kg) and polyaromatic hydrocarbons (PAH 1.64 μg/1 in lixiviate); and Case C (1680 m3) exhibited high PAH values (PAH 1.94 μg/l in lixiviate). The controlled addition of nitrogen and phosphorous sources and water increased bacterial counts of soil in all cases and resulted in a significant elimination of hydrocarbons: 32 % TPH in Case A after 7 months of treatment (from May to December 2005); 39 % TPH and 88 % PAH in Case B after 5 months (from October 2005 to February 2006) and 90 % of PAH after 3 months of treatment (from May 2005 to July 2005) were removed. In addition, we performed a comparative evaluation of natural attenuation, biostimulation and bioaugmentation (inoculation of bacterial strains) for bioremediation of PAH-contaminated soil in situ. Both, biostimulation and bioaugmentation promoted significant degradation (&gt; 90 %) of PAH after 6 weeks of treatment, whereas attenuation resulted in a reduced degradation rate (67 %). In conclusion, this study suggests that autochthonous bacterial communities from semiarid soils in Patagonia have the potential to degrade hydrocarbons after amelioration of unfavorable environmental conditions.
Offshore LNG Technology: A Comparative Study of Conventional and Futuristic Salt-Cavern-Based LNG Receiving Terminals
Authors: Rai Sanchit 
Published: December 2007

Abstract
Tight oil supplies, escalating oil prices, and towering energy demands have led to the revival of natural gas. It is now deemed as the potential fuel of the near future. The trend now is toward supplying every cubic feet of the inland and offshore natural gas to the energy hungry consumers. LNG is recognized as the best form of gas transfer from remote inland and offshore fields to the consumers spread worldwide.
The natural gas is liquefied and shipped to distant receiving terminals. The chief technical features of a conventional terminal facility include LNG carrier mooring systems, unloading facilities, storing LNG in cryogenic storage tanks, LNG regasification systems and gas send out systems. The US has five such conventional terminals. The US is world's largest gas market with its gas demands expected to double by 2020. This is leading to the expansions and refurbishments of these conventional LNG receiving terminals with the construction of several more under various phases of planning and development. Recently, in the year 2005 Department of Energy (US), with 30 energy industry players successfully completed a research study on the concept of an offshore facility to moor LNG carriers, unload LNG and store it. This concept includes storing gas in salt-caverns. This technology is claimed to be highly cost effective, process efficient, with better delivery capacity and security. This idea is being realized by the construction of such a modern LNG receiving terminal in offshore Louisiana.
This paper aims to present a qualitative comparison between the conventional and the futuristic salt-cavern-based LNG receiving terminal. The comparison is based on the technology employment for these terminals.
Apart from the US, the LNG also holds immense promise to countries like Brazil, China, United Kingdom, Mexico, Germany and France. These countries are also contemplating LNG-facilities development and up gradation. This paper will be significantly important in understanding the various technological aspects of conventional and futuristic salt-cavern-based LNG receiving terminals on a comparative basis. This approach will be ultimately useful in understanding the technology-implementation for the development and modernization of the LNG receiving facilities in such countries.
The Effects of Fracture Cleanup on the Productivity of Gas Condensate Systems
Authors: Jamiolahmady M. , Ganesh D. , Sohrabi M. , Danesh A. 
Published: December 2007

Abstract
The performance of fracturing treatments has been an issue for over fifty years and considerable effort has been devoted to improve its prediction performance. However, the effect of cleanup in tight gas-condensate reservoirs where fracturing considered as the most common well stimulation technique, has not been fully investigated for these low IFT systems. The performance of cleanup operation heavily depends on the mobility, i.e., viscosity and relative permeability (kr), of fracturing fluid compared to those of gas and condensate. This determines the extent of invaded zone near the wellbore region and the ease with which fracturing fluid is removed during the back-flow operation.
In this work, measured values of permeability, single-phase inertial factor and kr of a propped fracture and those of a tight reservoir rock have been used to evaluate the performance of fracturing treatments. ECLIPSE 300 compositional reservoir simulator, which includes our in-house kr correlations accounting for coupling (i.e., the increase of kr as velocity increases and/or IFT decreases) and inertial (i.e., the reduction of kr as velocity increases) effects, was used to develop realistic fractured flow systems. A sensitivity analysis on the impact of different hydraulic fracturing fluid, fracture characteristics and reservoir fluids on the productivity of a single-well model were conducted resulting in some practical guidelines.
The results indicated that the performance of 300 cp high viscosity fracture fluid is better than that of 10 cp low viscosity fluid, due to a lower penetration depth. When kr of oil based fracturing fluid is improved, compared to that of water based, the back flow of fracturing fluid is facilitated especially for the 10 cp low viscosity fluid. Presnece of condensate facilitate the backflow of fluid, hence, cleanup efficiency is better for richer fluid systems.
Development, Verification and Application of a Screen Erosion Model
Authors: Cameron John , Jones Colin 
Published: December 2007

Abstract
Sand control completions are an increasingly more significant part of the overall well cost as hydrocarbon developments are pushed into ever more challenging reservoirs. Successful project economics and performance hinges on reducing the risk and consequences of failure to a practical minimum. Erosion is often identified as the failure mode when investigating sand screen failures – even though the true root cause is often procedural or operational in nature. Determining the cause of such failures is nearly always problematical when the equipment cannot be retrieved to surface. Erosion is therefore perceived to be a major risk in cased hole sand control completions and even in high rate open-hole and water injection wells. The key to controlling this risk is an understanding of the erosion rate and how it affects the sand retention properties of the selected screen.
The results of a comprehensive set of erosion tests have been used to develop a erosion model which predicts probable time to screen failure based on fluid type, flux rate, solids loading and size distribution. The model has been verified against a number of actual screen failures and also to predict failure times based on specific completion designs.
Characterizing the Complex Shaly Sand Oil Reservoirs in San Jorge Basin, Argentina, Using Advanced Magnetic Resonance Techniques
Authors: Fam Maged Y. , Vieiro Julio A. 
Published: December 2007

Abstract
Evaluating the complex clastic reservoirs in El Tordillo field of the San Jorge Basin in Argentina using conventional logs is greatly affected by variations in formation water salinity, texture, and lithology (primarily the amount of volcanic tuff material) combined with extreme changes in rock permeability and wide variations in oil viscosity. All of these factors affect most of the conventional logs responses in such a way that traditional log analysis methods may fail to provide proper results and consequently may not achieve appropriate forecasts. Such failures have been proven by the high degree of mismatch between conventional log analysis and test/production results.
To address uncertainties in conventional log evaluations, operators may resort to excessive well testing for reservoir characterization and production verification. However, well testing is known to be costly (considering the rig time and the frac jobs used). On the other hand, if the operator does not proceed with well testing, productive zones can be bypassed. That is why an effective log evaluation would be the optimum, cost effective method when it demonstrates agreement with production results.
The latest acquisition and interpretation techniques of the magnetic resonance imaging logs (MRIL) have demonstrated promising results in the complex shaly-sand reservoirs of El Tordillo field. The magnetic resonance imaging (MRI) technology run on wireline provides an in-situ evaluation of the reservoir properties vital for producibility predictions. The ability of MRI to estimate the type of fluid in terms of viscosity influences the selection and elimination of zones to be tested based on their mobilities. MRI also helps in properly preparing for the testing procedure by pre-identifying the type of hydrocarbon in a zone and by identifying its reservoir quality in terms of permeability and porosity. Thus, the MRI serves well when determining the need for well testing and in enhancing the effectiveness of any particular well test.
This article discusses the effectiveness of applying the MRI logging technology to the characterization of the shaly-sands of El Tordillo field in both the Comodoro Rivadavia and Mina El Carmen formations. It also argues for the value of MRI technology in minimizing the cost (and associated risk) of well testing by identifying best candidate zones for testing and by providing necessary "prior-to-testing" information on the fluid type (i.e., water, light oil, heavy oil or gas) present in a zone and rock properties, such as porosity and permeability.