bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fiber-Enhanced Visco-Elastic Surfactant Fracturing Enables Cost-Effective Screenless Sand Control
Authors: Heitmann Norbert , Pitoni Enzo , Ripa Giuseppe , England Kevin 
Published: December 2007

Abstract
Many gas reservoirs in the Adriatic Sea, offshore Italy, are formed of laminated, low permeability dirty sandstones, requiring gravel packing for sand control. Numerous gravel-packed wells are either sanded up and shut in, or are underperforming due to fines plugged gravel-pack screens, which cannot currently justify the expense of an immediate and cost-prohibitive full rig workover. Frac and packs are performed to increase productivity bypassing near wellbore damage, interconnecting multiple sandstone layers and decreasing fluid velocities in the formation, thus reducing fines production. Significant interest exists to enhance fracture performance, deferring and reducing re-completion costs.
This paper discusses various rigless performed rehabilitations of failed sand control completions, highlighting the evolution of fracture fluid selection, optimization of the fracture placement and achieved geometries with seawater-based visco-elastic surfactant fluids and the use of speciality glass fibers for fracture pack stabilization and enhanced proppant transport. This combined rehabilitation technique enabled screenless sand control completion and is allowing low cost rehabilitation of plugged or failed sand screens and the development of any numbers of gas layers which otherwise could not be drained using conventional sand control technologies. This completion technology potentially allows to significantly adding gas or oil reserves, the development of the normally by-passed upper gas layers, which would require costly workover re-completion using conventional technologies.
Procedures, experiences and results are presented, validating the -enhanced visco-elastic surfactant fracturing concept enabling screenless sandface completion for controlling sand production. Rigless rehabilitation has confirmed being an efficient solution and allows cost-effective production increase.
Reliable Wax Predictions for Flow Assurance
Authors: Coutinho João A. P. , Edmonds Beryl , Moorwood Tony , Szczepanski Richard , Zhang Xiaohong 
Published: December 2007

Abstract
A number of wax models are currently in use by the oil industry which are based on parameters that were empirically determined to match available data for black oils. These data are often not very precise. The recently developed model of Coutinho is, however, based on high accuracy thermodynamic data.
The paper describes how the Coutinho model can be used in conjunction with conventional equations of state to perform wax equilibrium calculations for black oils. Examples are given showing how well the model can predict both wax appearance temperature and the amount of wax precipitated at varying temperatures with or without n-paraffin analyses. The examples include the effect of pressure on live oils.
Improved thermodynamic modelling of wax formation in turn allows better prediction of wax deposition rates for flow assurance.
A Stepwise Example of Real Options Analysis of a Production Enhancement Project
Authors: Bailey William , Mun Johnathan , Couët Benoît 
Published: December 2007

Abstract
Practical solution to a Real Options analysis of a somewhat generic production enhancement problem is presented. First the problem is properly framed, suitable data is gathered, the analysis is performed and finally the results are communicated. Ancillary issues concerning the most appropriate solution methodology and the quantification of a representative volatility component are also touched upon. The narrative is constructed in such a way as to, hopefully, enable usage beyond the specifics of the problem discussed. A form of visual representation of results is proposed that may facilitate communication, improve understanding and help gain acceptance of the benefits of such an analysis from management and decision-makers’ points of view.
Improving Team Capability and Efficiency by Moving Traditional Rig-Site Services Onshore
Authors: Wahlen M. , Sawaryn S. , Smith R. , Blaasmo M. 
Published: December 2007

Abstract
The continuous improvements in high-speed communications and information technology are transforming traditional drilling working practices. For some services such as data and LWD engineering, personnel no longer need to be physically present at the rig site. New technology guarantees their virtual presence. Instead, these positions can be moved onshore, adding to the overall team capability and efficiency. At the same time, this reduces the over all HSE exposure and offers further potential savings in bedspace and transportation costs. To effect this transition, each of people, process and technology challenges have had to be addressed. These concepts have been embodied in the "Baker Expert Advisory Center/Operations Network" (BEACON) system, established in Stavanger, Norway.
The paper describes the challenges faced in establishing the system and their solutions. Human factors are shown to play a crucial role in its successful implementation, demanding greater flexibility in onshore working practices to match those remaining offshore and to establish the virtual team. During the initial trial period, these factors, compounded by reliability and maintenance problems caused the system's operation to be suspended. Following a review, operations were restarted and two wells have now been successfully drilled in this operational mode. Improvement in the team's decision-making capability is evident and has been described as "increasing the team IQ". Improved access to the onshore centre, compared with offshore, is now shown to increase reliability and flexibility. Finally, the paper summarises the future work planned under the Norwegian Demo2000 sponsorship program, which will address the provision of these services in more formal terms.
Field Evaluation of Iron Hydroxide Gel Treatments
Authors: Kosztin B. , Palásthy Gy. , Udvari F. , Benedek L. , Lakatos I. , Lakatos-Szabó J. 
Published: December 2007

Abstract
A novel gel treatment technique based on transformation of water soluble Fe(III) compounds into gel-like precipitate by in-situ hydrolysis and flocculation was developed for water shut-off in mature oil fields. The new blocking material has excellent stability under field conditions, and yet simple remediation is possible in case of placement failures. Further, the novel method is characterized by self-controlling chemical mechanism and using this technique injectivity problems didn't arise even in low-permeability and tough formations.
The extensive field program was supported with special software determining the penetration distance from the wellbore. Based on log data, the pay zone was subdivided into a maximum of four layers assuming that crossflow among zones was negligible. Total volume of the treating fluids was obtained by asserting two limiting rules: the treating fluid must reach a minimum penetration depth (&gt;15 m) in the layer having the highest permeability, but the max. penetration depth should not exceed 2 m in the layer having lowest permeability.
The test program comprised treatment of ten oil producing wells and seven water injectors. The well responses varied between wide limits: technical success was achieved in about 60 % of the wells, and the treatment was economically beneficial in about 40 % of the cases. In special reservoir blocks the injector wells were simultaneously treated with the oil wells. The primary goal of this project was to enhance the effect of flow profile correction around the producers and to improve the frontal displacement mechanism. The new method was compatible with the dirty sandstone reservoir systems, and there were no technical failures. The positive results contributed significantly to the operator's decision to extend use of the new method to other reservoirs.
Simplified Prediction of Reservoir Pressure in Coalbed Methane Wells
Authors: Cooper Joshua E. 
Published: December 2007

Abstract
Prudent coalbed methane (CBM) reservoir management and optimization requires knowledge of reservoir pressure. This paper presents a simple three-step method to predict reservoir pressure throughout the producing life of a coalbed methane well using only initial reservoir pressure, Langmuir pressure and cumulative gas produced. Use of the method has the potential to significantly reduce operating costs by minimizing the number of pressure surveys required to understand, operate and optimize a well or reservoir. The equations and process used to predict reservoir pressure are discussed, results of simulation studies validating the method are presented and actual examples from Fruitland Coal wells in the San Juan Basin are used to test the applicability of the method to real world conditions.
A New and Robust Simulation Model for Coalbed Methane Reservoir
Authors: Jan Badrul M. , Siagian Ucok W. , Lee Robert L. , Othman Roslee 
Published: December 2007

Abstract
A new and robust approach was developed to simulate flow of methane gas in coalbed methane reservoirs. The proposed simulation model was developed for a 2-phase, 3-dimension, single porosity with desorption/adsorption phenomena. The model was developed based on mass balance concept and control volume approach. Flow of gas in the fracture is modeled by Darcy's Law, while movement of gas in the coal matrix is assumed to obey diffusive process. A new equilibrium equation is proposed to represent the process. To verify the developed model, we history matched Well # 1, an active gas well over a period of about 4 years. The well was producing from Fruitland formation in San Juan Basin, northwest of New Mexico. In addition, we also made prediction study of Well # 1 in which we investigated the effect of completion techniques (vertical vs. horizontal), fracture and stress sensitive permeability on the overall performance of Well # 1. The results of the study indicate that the developed model is able to predict the performance of a coalbed methane reservoir quite well. The model behaves as predicted and it closely matches the past performance of Well #1. The results also highlight the importance of stress sensitive permeability consideration in coalbed methane evaluation even in low fairway area of San Juan Basin where permeability is less than 1.0 md. Neglecting the effect may result in overestimation of reservoir performance. The study also suggests that fracturing job might be a crucial element to prevent Well # 1 from being shut down prematurely.
Medina Stimulation: Is Bigger Really Better?
Authors: Fontaine Jim , Paugh Len , Watson Jim 
Published: December 2007

Abstract
Over the past thirty years, the Medina sandstones have been the primary drilling target in northwestern Pennsylvania. Numerous operators have drilled and completed thousands of wells in this tight gas sandstone. As fracturing technology has evolved, many different types of treatments have been utilized; from "slickwater" fracs containing small volumes of sand pumped at low densities, to crosslinked gels carrying high volumes and densities of sand, to linear gels with widely differing sand volumes and densities, to nitrogen foams also transporting varying volumes and densities. While everyone agrees that Medina wells need to be stimulated in order to be productive, there are as many opinions as to the most successful technique as there have been operators. Often, these opinions are based upon conjecture with no comparative supporting data.
The Cramerven/Cooperstown field located in Crawford, Mercer, and Venango Counties provides an opportunity to review the history of Medina stimulation as well as compare the results of different frac styles. Wells in this field have been extensively analyzed and production tracked in order to determine the optimal stimulation technique. Although variability due to geologic differences can greatly affect the results of individual wells, large populations of wells have been compared in order to minimize the effect of this variability.
This paper will present a discussion of the historical stimulations performed in this field, compare stimulation design to Estimated Ultimate Reserves, provide background on the design and development of the treatments utilized, and finally, present an analysis of the current design based upon production decline analysis.
Automation of Casing Plungers for Increased Production
Authors: Gregg David 
Published: December 2007

Abstract
This paper will review the concept, use and current developments of casing plungers since their inception in the 1980's. Their use has only recently become a significant impact in artificial lift for producers.
The use of Casing plungers as a production tool in the USA has been developing for over 10 years. They have enjoyed a limited success as a valid production tool and are very specific in application.
Their success has been limited by some practices used during completion of a well and the internal conditions of the casing in older wells. There use in strings of casing with mixed weights has been erratic. Yet, the plunger has shown some very significant results in the production of gas from some very difficult wells.
The wells that have been able to apply this method of artificial lift, once found that the safe use of the casing plunger with its positive seals to be a prime issue when the plunger is in travel to the surface.
This includes the integrity of the casing with no damage to its interior walls. The use of varied weights of casing in a well string can also be an issue of concern.
The manufacturers of the casing plunger systems have limited the travel rate or velocity of the casing plunger by connecting the flow line to a tightly restricted orifice. This restricted flow has led to criticism of the production results that can be expected. The need for change of this design has led to a more successful operation.
There had been few developments in this equipment until the past few years. An effort to improve the production of the well with assuring a safe operation has led to a effort to design and develop a system that will yield optimal results.
The goals to develop an automated control system for the casing plunger were established. There had to be a Fail-safe control system that permits the production of a well in excess of what was possible with the current system.
It should create a longer life expectancy of the polymer seals that are affected by casing plungers cycling too often. The use of a free cycle plunger was dismissed as non-productive due to excessive wear on seals and dry runs.
The system should maintain higher production rates when the casing plunger is at surface. The seals should have a chance to stay in a low pressure lubricator to normalize.
All of these goals were to be a high priority in redesigning this system.
Mature Waterfloods Renew Oil Production by Alkaline-Surfactant-Polymer Flooding
Authors: Wyatt Kon , Pitts Malcolm J. , Surkalo Harry 
Published: December 2007

Abstract
The Illinois and Appalachian Basins contain many mature and economically marginal waterfloods. These fields produce at high water-oil ratios that have proportional fluid handling costs. Approximately 60% of the oil resource remains in the reservoir rock at these conditions. The Alkaline-Surfactant-Polymer, ASP, technology has been field demonstrated to recover 15% OOIP to 30% OOIP of this residual oil by minimizing capillary forces which trap oil, improving areal and vertical contact efficiency, and mobility ratio. Mechanisms of ASP flooding are discussed and field performance is compared with micellar technologies that were tested in the Illinois Basin.
Fundamentals of Developing a Surveillance Logging Quality Assurance and Quality Control Plan
Authors: Newman Mark A. , Hetznecker Paul F. 
Published: December 2007

Abstract
Developing a quality assurance and quality control (QA/QC) plan is an important element of any surveillance logging program. A QA/QC plan is used to document how quality assurance (QA) and quality control (QC) activities will be implemented during a program, project, or task1. A QA/QC Plan for a surveillance logging program can provide adequate and accurate information in assessing the level of pipe defects reported from casing inspection logs and can be used to record possible trends regarding the individual casing inspection tools. It may also analyze data to characterize errors in measuring tubular thickness as well as monitor tool accuracy and data interpretation.
Reservoir Modeling for Horizontal Exploitation of a Giant Heavy Oil Field - Challenges and Lessons Learned
Authors: Tankersley T. H. , Waite M. W. 
Published: December 2007

Abstract
The Hamaca Field, located in Venezuela’s Orinoco Heavy Oil Belt, is a giant extra-heavy oil accumulation operated by Ameriven, an operating agent company for PDVSA, Phillips and ChevronTexaco. Over the 35-year life of the field, more than one thousand horizontal laterals are planned in order to deliver 190,000 BOPD to a heavy-oil upgrader facility. Reservoir models are built to support a broad continuum of activities in order to meet this objective. This paper will review the Hamaca reservoir modeling process, the challenge of integrating many sources of geologic and geophysical constraints including horizontal well information, the focus on continuous model improvement, and issues unique to Hamaca rock and fluid properties.
New Solutions for Well Test Analysis of Horizontal Wells
Authors: Lu J. , Cunha L. B. , Lu T. 
Published: December 2007

Abstract
Horizontal wells are becoming popular for primary and enhanced oil recovery operations because of unique advantages of horizontal wells in comparison to those for vertical wells. For example, horizontal wells are being used, at present, for the primary recovery of heavy oil worldwide. They allow a larger reservoir exposure, which increases productivity, accelerate recovery, and reduce coning tendencies. However, horizontal well testing is considerably more complex than vertical well testing.
This work addresses new solutions for well test analysis of horizontal wells. With the similar methods in Ref. [1,2,3], taking a horizontal well as a uniform line sink in three dimensional space, by developing necessary mathematical analysis, this paper presents horizontal wells pressure drawdown and buildup analyses in a single porosity reservoir with a circular cylinder drainage volume.
The solutions obtained here which are based on three dimensional models are more accurate than the two dimensional model based well testing equations in the literature. Simplified solutions for short and long times that exhibit straight-line sections when pressure is plotted vs. time are presented. Methods for analyzing pressure drawdown and build-up data are presented. The method allows reservoir characteristics, including permeability, skin to be determined.
Horizontal Wells in Thermal Applications for Displacement and Gravity Drainage
Authors: Terez Ivan E. , Ehlig-Economides Christine 
Published: December 2007

Abstract
Reservoir simulation of injection and production well geometries for parallel horizontal wells with varied steam injection schedules was used to investigate recovery from primary production, displacement and gravity drainage processes. This revealed that the recovery following primary depletion is improved by placing the injector close to the top of the formation and the producer near the bottom. Once the steam chamber between injector and producer is formed and continuous, the gravity drainage mechanism becomes dominant. This regime is described as SAGD and the oil production is insensitive to steam injection rate.
The utilization of all three recovery stages results in 22-56% recovery with cumulative SOR of 4-5. The economic analysis (sensitive to specific oil/steam prices and discount factor) revealed that following primary depletion with the low rate drainage processes (SAGD) provided no increase in NPV over continuing primary production until the economic limit is reached. Following primary depletion with a higher rate displacement process on the original pattern or smaller pattern areas increased the NPV significantly.
Heavy Oil Carbonate: Primary Production in Cuba
Authors: Smith G. E. , Hurlburt G. , Li V. P. 
Published: December 2007

Abstract
Primary production has been carried out for more than 30 years from large overthrusted carbonate structures along the north coast of Cuba between Havana and Varadero. Long reach horizontal wells, with open hole completions, are used and extensive logging suites, including FMI, have been collected and analyzed. A huge amount of oil is held within the tight matrix but currently most of the produced oil is likely from macro and micro fractures, and breccia or vuggy porosity. It is postulated that primary production is supported by secondary gas in the fractures and "foamy oil". The EXODUS simulator has been used to model the system in dual porosity mode demonstrating the coning of gas and water in the fracture system and production from a "rim" of oil in the fractures at the level of the wells. Field observations and well performance also demonstrate the presence of gas in the fracture system and the high permeability necessary to drain the viscous oil.
Steam Conformance Along Horizontal Wells at Cold Lake
Authors: Smith R. J. , Perepelecta K. R. 
Published: December 2007

Abstract
This paper describes Imperial Oil’s success in identifying and remediating poor steam conformance in a horizontal well used in Cyclic Steam Stimulation operations.
Imperial Oil is conducting Horizontal Well Cyclic Steam Stimulation (HWCSS) at nine horizontal wells located at two pads in Cold Lake. Steam conformance along horizontal wells is a significant issue in these types of thermal applications. The horizontal wells are completed with Limited Entry Perforations (LEP) to improve distribution of steam along the liner. One of the HWCSS pads, D36, has been the subject of both 4D seismic and injectivity analyses to characterize steam conformance along the horizontal section over the first three cycles. These analysis techniques showed that four out of the five wells on the pad had excellent steam distribution along the horizontal liners. However, one of the wells, D36-H1 showed little or no steam conformance along the last half of the liner. This lack of horizontal steam conformance put the recovery expectations of this well at risk. A workover conducted on D36-H1 successfully removed sand that had been obstructing the liner. Steam injection subsequent to the clean out showed steam distributed across the majority of the liner (most of the LEPs accepting steam).