bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Permeability Prediction Relations for Low-Permeability Sands
Authors: Florence F. A. , Rushing J. A. , Newsham K. E. , Blasingame T. A. 
Published: December 2007

Abstract
This work addresses the problem of estimating Klinkenberg-corrected permeability from single-point, steady-state measurements on samples from low permeability sands. The "original" problem of predicting the corrected or "liquid equivalent" permeability (i.e., referred to as the Klinkenberg-corrected permeability) has been under investigation since the early 1940s — in particular, using the application of "gas slippage" theory to petrophysics by Klinkenberg.1
In the first part of our work, the applicability of the Jones-Owens4 and Sampath-Keighin5 correlations for estimating the Klinkenberg-corrected (absolute) permeability from singlepoint, steady-state measurements is investigated. We also provide an update to these correlations using modern petrophysical data.
In the second part of our work, we propose and validate a new "microflow" model for the evaluation of an equivalent liquid permeability from gas flow measurements. This work is based on a more detailed application of similar concepts employed by Klinkenberg. In fact, we can obtain the Klinkenberg result as an approximate form of our result. Our theoretical "microflow" result is given as a rational polynomial in terms of the Knudsen number (the ratio of the mean free path of the gas molecules to the characteristic flow length (typically the radius of the capillary)).
The following contributions are derived from this work:
Validation and extension of the correlations proposed by Jones-Owens and Sampath-Keighin for low permeability samples. Development and validation of a new "microflow" model which correctly represents gas flow in low permeability core samples. This model is also applied as a correlation for prediction of the equivalent liquid permeability in much the same fashion as the Klinkenberg model, although our new model is substantially more theoretical (and robust) as compared to the Klinkenberg correction model.
Unconventional Gas Recovery and Subsurface Water Mapping: A Relationship of Untapped Potential
Authors: Montgomery J. , Rollins Paul 
Published: December 2007

Abstract
Processes of unconventional gas recovery frequently have to deal with water issues. For the purposes of protecting both productivity and the environment, well operators must monitor the relationship between their extraction activity and the surrounding groundwater network. This is especially true in the case of hydraulic fracturing, when new fractures may facilitate communication with the local aqueous system. Well operators therefore have a vested interest in more effective methods for determining the size, shape, and flow patterns of subsurface water features.
This paper introduces a new water imaging technology and considers its implications for unconventional gas recovery. The technology uses Controlled Source-Frequency Domain Magnetics (CS-FDM) to map and model underground water features. Its rapid and minimally invasive procedure has now been effectively implemented in a variety of ground-water projects. The results of those projects suggest that it possesses significant potential value for the natural gas industry. This paper will serve as the beginning of an overdue conversation about its merits and possibilities in that field.
One of the most relevant applications of this technology has come in the area of improved oil recovery. By applying the technology's water-mapping capabilities to oil reservoirs that have been flooded with water or steam, field operators have been able to quickly and accurately characterize the features of those reservoirs and thus develop more effective stimulation strategies. At this stage in the technology's development, it is time to ask whether it can serve a similar function in unconventional gas production. That is, can a tight-gas feature or coal bed which has been filled with fracturing fluid, take advantage of CS-FDM's capacity for reservoir characterization? The answer to that question could have major implications for production well placement, facilitating increased output and minimizing environmental impact, and also for evaluating hydraulic fractures
Development of an Improved Methodology to Assess Potential Unconventional Gas Resources
Authors: Salazar J. , McVay D. A. , Lee W. J. 
Published: December 2007

Abstract
Considering the important role played today by unconventional gas resources in North America and their enormous potential for the future around the world, it is vital to both policy makers and industry that the volumes of these resources and the impact of technology on these resources be assessed. To provide for optimal decision making regarding energy policy, research funding, and resource development, it is necessary to reliably quantify the uncertainty in these resource assessments.
Since the 1970's, studies to assess potential unconventional gas resources have been conducted by various private and governmental agencies, the most rigorous by the United States Geological Survey (USGS). The USGS employed a cell-based, probabilistic methodology, which incorporated simplifying assumptions to derive analytical equations to calculate distributions of the resources assessed. USGS assessments have generally produced distributions for potential unconventional gas resources that are unrealistically narrow for what are essentially undiscovered, untested resources.
In this paper we present an improved methodology to assess potential unconventional gas resources. Our methodology is a stochastic approach that includes Monte Carlo simulation and correlation between input variables. Application of the improved methodology to assessment of potential unconventional gas resources in the Uinta-Piceance province of Utah and Colorado with the USGS data validates the means and standard deviations of distributions produced by the USGS methodology, but reveals that these distributions are not right skewed, as expected for a natural resource. Our investigation indicates that the unrealistic shape and width of the gas resource distributions are not caused by lack of correlation between input variables, but rather the use of narrow triangular input parameter distributions.
The stochastic methodology proposed here is more versatile and robust than the USGS analytic methodology. Adoption of the methodology, along with a careful examination and revision of input distributions, will allow a more realistic assessment of the uncertainty surrounding potential unconventional gas resources. Reliable assessments of uncertainty are important in the decision-making process for exploration and development of potential unconventional gas resources, and will be valuable to both government and industry in the timely development of unconventional gas resources for the public benefit.
Recent Acid-Fracturing Practices on Strawn Formation in Terrell County, Texas
Authors: Zaeff G. , Sievert C. , Bustos O. , Galt A. , Stief D. , Temple L. , Rodriguez V. 
Published: December 2007

AbstractThe goal of an acid fracture treatment is to generate a highly conductive pathway of sufficient length from the reservoir to the wellbore. Depth of penetration of live acid is the critical factor in determining the success of an acid-fracturing treatment. Depth of penetration is controlled by the acid reaction rate, leakoff, and stimulation rate. Acid reaction rate is a function of several factors, the most important of which is the reservoir temperature. Yet another concern, in acid fracturing in long carbonate intervals, is attaining the necessary diversion to ensure that multiple sets of perforations are adequately stimulated.Because of their high solubility and highly fractured/vugular nature, carbonate reservoirs in the Permian Basin show excellent response to acid fracturing treatments. However, inadequate diversion can leave substantial portions of the reservoir untreated. Different acid systems have been developed to counter the problems in acid fracture stimulations. Chemical and mechanical means of diversion have been used with varying degrees of success. Likewise, there have been many attempts made in retarding the reaction rates of hydrochloric acids in high temperature environments. Recently, there has been a large number of highly successful acid fracture treatments in the Permian Basin incorporating a combination of new polymer-free self-diverting acid combined with an existing acid-oil emulsion technology.120This paper will discuss a combination of technologies, which has recently been applied successfully in the Strawn formation in Terrell County, Texas. It will also focus on what is being done to mitigate the affect of high temperature on hydrochloric acid's reaction rate. It will further develop improvements in reservoir characterization and pay zone determination, which has been improved by the utilization of resistivity imaging logs. Some examples presented contain information from radioactive tracers and production logs, which are fundamental to understanding how good zonal coverage was achieved using different techniques. Additionally production analysis has been conducted to determine the effective fracture half-length and etched conductivity. Finally, a relative comparison between the old and new completion methodologies is made taking into account that the new completion practices have only been applied in full combination since 2004.
A Novel Foamer for Deliquification of Condensate-Loaded Wells
Authors: Orta D. , Ramanchandran S. , Yang J. , Fosdick M. , Salma T. , Long J. , Blanchard J. , Allcorn A. , Atkins C. , Salinas O. 
Published: December 2007

AbstractContinuous increase in worldwide brown-field activity and overall depletion of current gas fields has renewed focus on maximizing gas production from existing wells. In most gas wells, water and/or condensate is produced along with gas. In mature gas wells, decreasing formation pressures and gas velocities gradually cause the wells to become "loaded" with liquids. A method commonly used to deliquify these wells is through the application of chemical "foamers". However, these traditional foamers tend to be ineffective as the condensate-to-water ratio increases. This paper describes the performance of a novel foamer specifically designed to unload condensate from wells. This foamer helped unload a gas well that produced condensate via intermittent production at 2:1 condensate-to-water ratio. Parameters for well selection are described, as well as operational processes to maximize continous production. As a result of this treatment, the daily average gas production rate increased significantly and shifted the daily on:off production cycle from 1:1 to 11:1. This minimized well down time and increased the overall daily production averages by 60 percent.
Application of Indirect Fracturing for Efficient Stimulation of Coalbed Methane
Authors: Olsen T. N. , Bratton T. R. , Donald A. , Koepsell R. , Tanner K. 
Published: December 2007

Abstract
Propped hydraulic fracture stimulation has been one of the primary completion methods for coalbed methane wellbores for more than twenty years. However direct fracturing of coal seams has been notoriously inefficient. High fracture pressures in coal seams, coal cleating and natural fractures can lead to shear slippage and inefficient non-planar fracturing which significantly underperforms the stimulation potential compared to conventional clastic rock fracture stimulation. In 2003 the concept of indirect fracturing was introduced to significantly increase Coalbed methane (CBM) fracturing efficiency by initiating fractures in lower stress clastic rock adjacent to coal seams and allowing these induced fractures to connect and grow into the coal seams. This paper presents several examples of the application of indirect fracturing for the stimulation of coal seams in the Rockies. This paper evaluates production results, fracture pressure analysis, as well as micro seismic results and frac tracer analysis for quantifying the effectiveness of indirect fracturing for the stimulation of CBM reservoirs. From this data we present guidelines for when and where indirect fracturing is applicable and just as important, where indirect fracturing is not appropriate.
Optimization of a Scale Treatment in the Uinta Basin—A Case History
Authors: Maschio Leonardo , Cherian Bilu , Lungwitz Bernhard , Tyndall Michael , Garcia Marieliz , Longwell John 
Published: December 2007

Abstract
The precipitation and accumulation of scale deposits is a major concern for production companies in the Uinta Basin. Since 2003, conventional hydraulic fracturing treatments with scale inhibitor pumped simultaneously as an additive have been offered to this region. This service proved to be very effective in the Permian Basin using borate crosslinked fracturing treatments (with scale inhibitor concentrations as low as 5 gal/mgal). However, these design criteria and formulation of the scale treatments had to be changed significantly to be effective in the typical Uinta Basin gas well environment: low permeability (&lt;0.1 md), multi-layered, commingled gas reservoirs. Typically, a well completed and placed on production without any scale inhibitor in the Uinta Basin may show signs of scale buildup in as little as 30 days. The effects of the scale accumulation can be seen everywhere from an exaggerated production decline to scale deposition on production equipment. This paper outlines the learning procedure and present designs, testing and monitoring results from scale treatments together with a case study from the Uinta Basin.
Analytical Evaluation of Gas/Condensate Skin in Hydraulically Fractured Wells
Authors: Ravari Reza Rostami , Wattenbarger Robert A. , Doust Alireza Rezaei , Amani Mahmood 
Published: December 2007

Abstract
The work in this paper is a result of a problem encountered in producing a low permeability formation from a hydraulically fractured well in South Texas. The well was producing from a tight gas condensate reservoir and there was concern about damaging the well if the wellbore pressure fell below the dew point. However, it turned out that condensate damage was not a problem. Lower wellbore pressures only resulted in higher rates.
This study employs analytical methods to evaluate production impairment by use of fracture face skin concept, sff, which is a permeability reduction normal to the face of the fracture. Due to very tight formation and presence of infinite conductivity fracture which propagates the entire drainage boundary of the well, the flow pattern from the formation into the hydraulic fracture is linear. The reservoir was modeled by a synthetic single phase linear model and the simulation results were compared to analytical solutions. In order to investigate if the analytical equations properly quantify the production impairment, at this stage the single phase fluid model was used to ignore productivity decrease due to condensate damage.
Single-phase damage analysis shows that for a linear reservoir producing at constant rate conditions, sff is additive to the analytical solutions. It also shows that sff calculated in transient and pss periods are identical to that calculated by using Cinco and Samaniego equation.
The same analysis for the constant pwf case assuming that the sff is additive to the analytical solutions shows that the calculated skin in transient period changes with time.
Challenges and Solutions in Hydraulic Fracture Jobs in Land Fields in Alagoas, Brazil
Authors: Payão Edson , Gomes Luiz 
Published: December 2007

Abstract
In this paper, we will describe techniques used to overcome the problems faced on the hydraulic fracturing jobs during the oil-to-gas conversion campaign in the Pilar field, Brazil.
The increasing demand for clean-burning natural gas in the Northeast of Brazil is fueled by the region‘s industrial growth over the recent years, and represents the main drive for the oil-to-gas conversion campaign witnessed in the wells previously producing at marginal oil rates from the Coqueiro Seco formation in the Pilar field. These old wells are now producing gas from the 3000 meters deep Penedo sandstone formations. One of the main steps to meet the goals for natural gas output in the Pilar field was the hydraulic fracturing campaign in the deep Penedo formation. The treatment design and execution process to create these fractures was quite distinct from the normal jobs aiming at increasing the oil productivity in wells producing from the shallow Coqueiro Seco formation.
The Barra de Itiúba gas-bearing formation in the Furado, São Miguel dos Campos and Cidade de São Miguel dos Campos fields was also included, to a lesser extent, in the stimulation campaign aiming at the increase in natural gas production.
This paper describes the completion strategy for the old wells converted from oil to gas producers, highlighting the problems faced and overcome during the hydraulic fracturing campaign. In deviated wells crossing the deep Penedo reservoir, the risk of multiple fractures and influence of tortuosity have been diminished through corrective techniques, unique for each one of the existing wells. In the early hydraulic fracture treatments performed in the Pilar field, premature screen-outs were commonplace, disencouraging the use of the technique. The need to produce gas brought new ideas to the battlefield, and their implementation led to results beyond expectations.
Produced Water Reinjection in Mature Field With High Water Cut
Authors: Navarro William , Muro Leytzher 
Published: December 2007

Abstract
This paper describes the current development and acquired experiences obtained in a produced water re-injection (PWRI) project in high WOR mature oilfields located in the Amazon rainforest in Peru.
Pluspetrol operates Block 8 and Block 1-AB, both located in the Northern part of Marañon foreland basin in Peruvian jungle. Twenty-four oilfields had been discovered between 1971 and 1980 and they have been producing since 1978. Currently 174 wells are producing from 17 fields with average water cut as high as 95%.
Productive reservoirs are composed of fluvial, estuarine and shallow marine sandstones from Vivian and Chonta formations of Cretaceous age. Main reservoirs have lateral continuity with porosity between 12 and 24% and permeability between 50 md and 5000 md.
The production mechanisms are bottom and edge water drive. It is observed that water cut in these reservoirs shows a very sharp increase to values above 90% in early stages of exploitation due to mobility differences between viscous oil and formation water.
In a first stage a series of injectivity test were performed in both shallow and deep reservoirs. These tests showed a better injectivity in deep reservoirs like Vivian and Pozo.
At the beginning injection rates were under matrix conditions but later with the aid of thermal effect and high injection rates, injection under fracturing conditions was achieved allowing us to increase injectivity index and thus reducing the number of required water disposal wells.
Artificial-Lift Systems Overview and Evolution in a Mature Basin: Case Study of Golfo San Jorge
Authors: Hirschfeldt Marcelo , Martinez Paulino , Distel Fernando 
Published: December 2007

Abstract
The Golfo San Jorge basin, located in the central Patagonia, is the oldest productive basin of Argentina, where the first economic discovery took place in 1907, in Comodoro Rivadavia.
With 11,680 active oil wells, is the first oil producer basin of Argentina producing 258,549 bpd of oil and 2.56 MM bpd of water.
The main characteristics of the basin are: –Faults and sand stone lens–HWOR–Increasing fluid flow rate per well–Complex fluids: corrosive, heavy oil, gas, sand and scale–Multiphase fluids–Multilayer reservoir: from 1.800 to 9000 feet
In this context, the selection, operation and optimization of the different Artificial Lift Systems (ALS) plays an important role for following the development of the basin.
This paper describes the best practices, experiences and trends, using ALS as Progressing Cavity Pump(PCP), Electric Submersible Pump(ESP) and Sucker Rod Pumping(SRP); and a basic description about Gas Lift, Plunger Lift and Hydraulic jet Pumping experiences.
Information as pump depth, flow rates, operational conditions, surface and sub-surface installations description, technical limits, failures statistic and new technologies from more than 9,000 active wells from different oilfields were collected and analyzed.
As result of this overview, an ALS reference guide was completed with parameters and benchmarking indicators; and some important conclusions appear.
Complementary information will be presented in the Appendix (Fig-A1, A2, Table-A1, etc)
Speeding Up Oil Recovery by Infill Drilling Prior to Considering Implementation of a Full-Field WAG Process–El Furrial Field, Venezuela
Authors: Leonardo Lopez G. , Rivas Analiesse , Bello Joaquin , Cordoba Pablo 
Published: December 2007

Abstract
El Furrial field is located in the Eastern part of Venezuela. The OOIP is about 7,500 MMSTB and the current daily production is 400 MSTBD. Due to the rapid pressure decline and the risks of asphaltene deposition, Enhanced Oil Recovery (EOR) processes have been implemented by water injection at the flank areas since 1992 and gas injection at the top of the structure since 1998.
Technical economical feasibility of infill drilling has been evaluated prior to considering the implementation of the full-field Water Alternating Gas (WAG) process. The main goal is to speeding-up of the recovery associated with the current EOR schemes. The applied methodology is based on maximization of the Net Present Value (NPV) under various schemes of production including new infill drilling.
The combination of numerical simulation results and economical analysis have led to a particular configuration of infill locations that will allow the extension of the current production plateau from 2007 to 2010. Incremental recovery after 20 years are as much as 250 MMSTB and the NPV could be increased more than 5000 MMUS$. Additionally, areal and vertical gas and water sweep efficiency is expected to improve with the optimization of the new well locations and the use of selective completions. This production plan would allow maximizing the efficiency of the current EOR schemes before implementing a WAG process.