bluuebunny/crossref_metadata_2025_split huggingface dataset:
Computer-Based Engineering Evaluation on Underground Waterflooding Fields in the Appalachian Region
Authors: Zaghloul J. , Farías M. , Ertekin T. , Watson R. 
Published: December 2007

Abstract
The Appalachian region contains hundreds of oil fields that were developed during the late 1800's and early 1900's. These fields contain oil reserves that may be recovered using secondary recovery methods such as waterflooding. Technical and economic evaluation of these fields for these capital-intensive operations requires in-depth engineering studies that usually include a field-scale computer model.
The objective of this study is the computer based engineering assessment of the mechanisms attendant to waterflooding of Gordon sandstone fields located in the Appalachian basin. To accomplish this objective, two case studies are presented. One is the Washington-Taylorstown field in Pennsylvania and the other is the Wileyville field in West Virginia.
The computer models developed include the history matching of the production data and the analysis of dynamic skin factor. The history matching protocol utilizes a systematic approach to complete the simulation of the historical data, which proved to be effective in understanding the behavior of the reservoir under study. It was concluded that the change in skin with time in waterflooding operations is not only due to matrix permeability variations; but also external factors such as mixed fluids injection, suspended particles and particle deposition.
The results obtained provide the operators of the Appalachian basin with a tool to characterize, initialize and perform computer simulation studies of any of the hundreds of reservoirs in the basin.
Stripper Well Consortium Offers Opportunities and Technologies to the Stripper Well Industry
Authors: Covatch G. L. , Morrison J. 
Published: December 2007

Abstract
As the United States moves to become less energy dependent on foreign sources, the importance of production from domestic stripper oil and gas wells will be much greater than it is today. Currently, stripper oil wells account for 15 percent of total domestic oil production and stripper gas wells account for 8 percent of total dry gas production. The importance of stripper wells is also reflected in that they represent 77 percent and 63 percent of the country's total oil and gas well populations respectively. Therefore, developing inexpensive technologies will be key in keeping these wells productive and helping the nation meet its energy demand.
In an effort to help maintain the production from stripper wells, the Department of Energy provides funding to the Stripper Well Consortium (SWC) to develop and demonstrate technologies that will improve the production performance of stripper wells. The SWC was established in 2000 and has cofunded over 60 projects since its inception. The SWC is an industry-driven organization and all projects are selected by a seven-member Executive Council elected for member organizations. Several projects have been completed and are now being offered commercially. This paper will focus on the operation of and the opportunities offered by the SWC, as well as highlighting a few of the successful projects such as the Gas Operated Automatic Lift (GOAL) PetroPump, the Vortex flow tools, the hydraulic diaphragm electrical submersible pump, and the new novel Weatherbee pump/compressor.
Review of Current Fracture Stimulation Techniques for Best Economics in Multilayer, Lower-Permeability Reservoirs
Authors: McDaniel B. W. 
Published: December 2007

Abstract
Currently, thousands of wells are being drilled every year in low- to moderate- permeability sandstone and carbonate reservoirs that have many distinct zones or layers that can contribute to production if adequately stimulated. In lower-permeability reservoirs, and especially for CBM completions, well economics will limit how much can be spent on the stimulation portion of a completion program. Operators may have to execute a "balancing act" with the need to maximize return on investment (ROI) while trying to complete as many contributing zones as possible. This usually drives a well operator toward methods that can minimize the number of separate well interventions while maximizing the number of zones that can be effectively stimulated.
This paper provides a State of the Art review on both old and newer completion/stimulation techniques that can help an operator accomplish production goals. When the fracturing treatments are pumped down the casing, different methods applied can vary from simple, single-stage fracturing treatments using "limited entry" perforating to multi-stage fracture treatments with bridge plugs (BP) or ball/baffle stage isolation. Additionally, there are various other techniques incorporating conventional tubing strings with or without packers or BP's, and even various methods for coiled-tubing (CT)-deployed treatments.
A "scorecard" approach presented here may offer operators an improved understanding of when a certain completion method is appropriate or flawed, based on the operators’ current understanding of specific reservoir characteristics of their field or well. Too often, a multilayer completion technique has been applied to several wells and later found to be a poor choice. The wrong choice may have been made because of a limited understanding of the completion method, or even of the reservoir itself. Often, an operator understands the variances of the reservoir, but does not realize the limitations that these variances should bring to the process of choosing the optimal simulation/completion method. In some cases, the choice has simply been made to take the low-cost completion/stimulation approach, and the resulting well(s) did not produce at (or sustain) economic levels.
(HC)3 Hydrocracking Technology
Authors: Lott R. K. , Lee T. L. K. , Quinn J. 
Published: December 2007

Abstract
Refineries are processing bottoms and heavy oils to lighter products using either thermal cracking base technologies such as visbreaking, delayed and fluid coking, or solid catalyst base low to moderate hydroconversion technologies using fixed bed and ebullated bed reactors. Unconverted resid from ebullated bed reactor has also been fed to delayed coker to increase the distillates yield. These processes perform well for what they are designed to do. With the new fuel specifications of 10–50 parts per million sulfur restriction in transportation fuels, distillates produced from low conversion fixed bed and ebullated bed hydroprocessing will not meet the required ultra low sulfur content without further hydrotreating. For distillates produced from delayed and fluid coking, even more severe secondary processing is needed to reduce the aromatic and sulfur contents in order to meet the new fuel regulations. In light of the current high crude price, general decline in crude quality, and regulations mandated high quality, ultra low sulfur specifications for the transportation fuels, significant advantages exist for flexible technology that can overcome limitations of current bottoms of the barrel upgrading processes.
The Alberta Government formed the Alberta Oil Sands Technology Research Authority (AOSTRA) in the 1970's to fund research and development of technologies to improve the economics of producing synthetic crude oil from its vast reserves of heavy oils and oil sands. These research programs provided new insight on the molecular structure of heavy oil, the chemistry of the various non-volatile fractions, especially on their tendency to form carbonaceous solids (coke) during upgrading. In the mid-1990's researchers at the Alberta Research Council (ARC) and AOSTRA developed a new upgrading technology called (HC)3TM, a hydro-conversion process that is designed to efficiently convert bottoms and residua rich in metals and asphaltenes to lighter products.
In 2001, Headwaters Heavy Oil, Inc. (HHO), obtained a worldwide exclusive license from the Alberta Science and Research Authority (ASRA) to commercialize and market the (HC)3TM hydrocracking technology. The This paper describes the (HC)3TM technology, its applications to improve operations at existing supported catalyst hydroprocessing facilities and as a stand alone hydrocracker.
Strategies for Unraveling the Mystery of Low-Resistivity Pay Zones
Authors: Myers R. R. , Batcheller G. , Phipps S. 
Published: December 2007

Abstract
In the Appalachian Basin gas wells are air-drilled and a multi-zone well stimulation are the normal completions. The majority of these wells are logged with air in the hole after removing the fines from drilling using compressed air. The sandstones in the Devonian series of the Appalachian Basin are listed in Table 1. These are associated with thinly bedded laminated sand shale sequences causing the Resistivity log to be lower. Many producing gas zones may be defined as so-called low resistivity pays.
Table 1 After Laughrey and Harper7, 1986, listing of gas well targets in Pennsylvania. Devonian Riceville Formation Venango Group Gantz Fifty-Foot Thirty-Foot, Upper Nineveh Snee, Lower Nineveh Gordon Stray, Boulder Gordon, Third Fourth Fifth Fifth Stray Bayard Bayard Stray Elizabeth Chadadoin Formation Pink Rock Bradford Group First Warren Second Warren Third Warren Speechley Stray, Upper Speechley Speechley Tiona First Balltown Second Balltown Sheffield, Third Balltown First Bradford Second Bradford Third Bradford Kane Elk Group Haskill, Riley, Elk Benson, Humphrey Alexander
Normal logging programs do not respond properly to thin or very thin pay zones which will be averaged with surrounding shales. This log response can cause pay zones to be overlooked as stimulation candidates. Information can be found from openhole logs in air filled holes, using a different methodology, to more accurately determine producing gas zones.
Appalachian Basin gas zones of the Upper Devonian section will be analyzed. A strategy will be recommended to help determine which zone(s) contain producible gas reserves or may not be worthy of hydraulic fracturing treatments. These decisions could have significant economic implications for operators. Appalachian Basin log examples, stimulation design and production response will be included as part of this investigation.
Crosslinked Gel Provides Long-Term Control of High-Pressure Gas Well During Coiled-Tubing Fishing: Challenges and Success Story
Authors: Nwoke L. A. , Uchendu C. V. , Ubani O. O. , Button J. , Arukhe J. O. 
Published: December 2007

Abstract
Identifying suitable kill fluids to temporarily control prolific oil and gas reservoirs without risk of formation damage has been a challenge within the Niger Delta. Various attempts, particularly in gas wells using conventional brines and gels to enhance well intervention processes normally require stimulation treatments, in order to bring the wells back to production.
The engineered cross-linked gel is a temporary blocking formulation used to protect permeable zones from invasion of fluids. This system contains a low-residue cellulose-polymer with a cross-linking agent and can be designed for use with an internal or external breaker. In general, the use of loss circulation material (LCM) is not recommended because of its tendency to block perforations, complicate fishing operations and increase the difficulty of clean-up if fishing becomes unsuccessful.
This case study is of a gas well drilled and completed for an Operator on the E4.2-reservoir with production capability estimated at 8,000 bbl/day of condensate and 150 mmscf/day of gas. Following the installation of the memory gauges, a 10- hour build-up test of this particular interval was conducted. During the retrieval of the BHP gauges, several incidents lead to three successive fishes getting stucked into the wellbore. The Operator was faced with many challenges: ‘do nothing and produce the well in an unsafe manner at 50% potential’, ‘attempt a workover’ or ‘attempt a coiled tubing rigless intervention’, with each option having its attendant limitations.
The success in retrieving the multiple fishes was attributed to the ability to kill the high pressure gas well with a time dependent and acid degradable cross-linked gel system through a high rate bullhead pumping technique. The gel had low damage potential to the formation and prevented the migration and fingering of formation gas to the surface throughout the fishing operation that lasted for approximately one month on 24-hour daily operations. The pre-fishing conduit potential was preserved, indicating that the cross- linked gel completely got degraded internally at the end of the fishing operation leaving the near wellbore region undamaged.
In this paper, the laboratory simulation, features, engineering design, field application and benefits of the engineered cross- linked gel system are discussed. In addition, the process of well killing, specialized coiled tubing and wireline fishing tools and performance evaluation are addressed. The success of the operation includes regain of the original well performance, competence in well killing and complex fishing, cost savings and high NPV. Over $2.0 million was saved operationally with the CT rigless activity when compared to ‘workover’ or ‘do nothing’ options.
Rock Physics and Time-Lapse Monitoring of Heavy-Oil Reservoirs
Authors: Schmitt D. R. 
Published: December 2007

Abstract
Production of hydrocarbons from heavy oil reservoirs often requires large investments both in capital and in operation and despite the best efforts portions of the reservoir may be bypassed or injected fluids may be lost. Time-lapse geophysical methods have shown promise in monitoring such reservoirs, particularly in the case of weakly consolidated sands. The seismic response can depend on a variety of factors that include temperature, pore pressure, stress, fluid saturation state, and material damage. These effects are briefly reviewed in the context of Gassmann's relation that predicts the compressibility, rigidity, and density of a saturated porous rock. While Gassmann's relation is widely used in fluid substitution studies, it is not yet clear whether it can be appropriately applied in the context of viscous heavy oil reservoirs.
Results From a Field Trial Using New Additives for Fracture Conductivity Enhancement in a High-Gas Screenless Completion in the Jauf Reservoir, Saudi Arabia
Authors: Al-Ghurairi F. , Solares R. , Bartko K. , Sierra L. 
Published: December 2007

Abstract
Saudi Aramco has been conducting a successful fracturing for sand control strategy in high pressure/temperature high gas rate screenless completions in the Jauf sandstone, which exhibits high sanding tendency in certain zones throughout the reservoir. The strategy combines a number of techniques, including indirect fracturing from oriented perforated thin consolidated zones, tip screenout design, use of a combination of resin coated proppant (RCP) with fibers, forced closure, and a carefully controlled flowback procedure.
Although solids-free high rate gas production has been achieved in the majority of wells for which the strategy has been implemented, a reduction in fracture conductivity in the form of positive skin has been detected in several hydraulically fractured wells in which pressure buildup tests have been conducted. Part of this negative effect results in all likelihood from partial perforation effects, given that the interval from which a fracture is initiated is usually perforated in high Young's Modulus rock and limited to 30-40 feet. Thus, the fracture is initiated away from the high sanding tendency zones and extended into such zones. The other main component for the positive skin are the fibers used for proppont flow back control purposes since it is well known through extensive industry testing that the combination of resin coated proppant and fibers can reduce fracture conductivity in treated wells.
Lab testing aimed at identifying potential conductivity reduction mitigation techniques, while maintaining the ability to achieve effective formation sand control, showed that the combination of two new additives, when mixed with proppant, was able to achieve both key requirements. Hence a suitable candidate was selected for a field trial.
This paper discusses the results of the first field trial of the additives tested as an alternative to the resin coated proppant/fibers mixture and the lessons learned from the trial. A direct comparison between the well treated with the new additives and an offset well previously treated with resin coated proppant and fibers, showed that the well treated with the new additives yielded better productivity despite the fact that its kh was only 1/3 of the kh of the offset well. A posttreatment pressure buildup tests was conducted in each of the wells for a valid comparison.
Challenging Convention in Sand Control: Southern North Sea Examples C
Authors: McPhee C. A. , Farrow C. A. , McCurdy P. 
Published: December 2007

Abstract
Sand production is a major issue facing many operators in the mature Southern North Sea gas fields. Historically, sand control completion decisions have often been based on the assumption that sand control will occur and have been constrained by the restrictions imposed upon sand entering the gas transport pipeline. The inherent conservatism of this approach leads to significant increases in completion costs and misses potential productivity gains.
A holistic sand management strategy has been developed for the Southern North Sea to challenge the conservative paradigm. This is based on a complete understanding of SNS reservoir rock properties and sand control completion performance in gas wells and has been tuned by learnings from SNS and analogue fields. It couples sand failure prediction, methodical and structured sand control selection (including consideration of production performance, longevity and risks) with novel solids lifting and erosion assessment models to better quantify the risk and consequences of sand production on wells and facilities. Key selection criteria are utilised rather than an arbitrary decision based on limited and often unaudited data. The role of an asset focal point with clear ownership of all relevant sand production data and issues is fundamental to the success of the integrated strategy.
Tools are available to predict when, where and even how much sand will be produced; how much sand will be lifted to surface; and how much erosion it will cause. Methodologies are available to evaluate and rank the available sand control techniques in a consistent and systematic manner.
This more systematic and integrated approach to sand management has enhanced well productivity and reduced completion costs without compromising sand management or exceeding sand production constraints. Challenging sand management convention in the demanding environment of the Southern North Sea compels operators to use these methodologies to much greater effect.
Clean Development Mechanism—The SPDC Afam Power Project
Authors: Ozumba C. I. , Amam S. E. , Pepple N. E. 
Published: December 2007

Abstract
The Kyoto Protocol, established to address climate change issues and the impact of Greenhouse Gas (GHG) emissions into the atmosphere, went into effect on 16th February 2005. The Clean Development Mechanism (CDM) is a product of this Protocol and one of the three-market mechanisms set up to help nations and industries meet their emission reduction targets. The CDM is an important element of Shell's Sustainable Development efforts.
Afam CDM, the most advanced in SPDC and one of the first in Nigeria was developed as a pilot ‘learning by doing’ project to access the emerging carbon market. Afam CDM is built around the development of a power generation project involving the replacement of old inefficient generating plants with Combined Cycle Gas Turbines (CCGT). This would displace inefficient power sources and contribute to a reduction in emissions.
The project was accepted by the World Bank Global Gas Flaring Reduction (GGFR) Partnership Initiative as a CDM demonstration project. GGFR was established to supplement and strengthen efforts made by governments and companies to reduce and eventually eliminate flaring. It considers CDM an important means of achieving flare reductions and also sees such projects as central to the objectives of the Kyoto Protocol. Nigeria, as a significant contributor to global gas flaring is a signatory to the Kyoto Protocol and is deeply committed to reducing gas flares in the country.
The benefits of this project include the creation of circa 2 million Certified Emission Reductions (CER's) per annum for 7-14 years, enhanced reputation, promotion of sustainable development, amongst others. The key issues, challenges and the strategy for achieving success in this project are discussed.
New Frac-Pack Design Technique Leads to More Accurate Estimation of Tip Screenout Post-FET
Authors: Edwards W. J. , Gauthier S. R. , Clarkson Brad A. 
Published: December 2007

Abstract
When the first frac pack was performed in the Gulf of Mexico (GOM) over a decade ago, very little was known about the effects this form of sand control would have on the intended formation. Even less was known about how to optimize the treatment to get the most benefit for the formation. Since that time, the sand control community has learned a great deal about the effects and benefits of frac packing various unconsolidated formations throughout the world. However, most of the knowledge and design criteria have been housed within the minds of individuals and cannot be looked at as a whole to find trends and fine tune the design methods currently being used. Another complicating factor is the number of frac models being used within the industry with varying degrees of complexity. Therefore, even though thousands of frac packs have been performed globally, frac-pack redesign methods are still subjective and differ from individual to individual and model to model.
The recent creation of a database that houses selected formation evaluation test (FET) and frac data, along with model-specific parameters, allows full-scale analysis of a large number of jobs pumped in the Gulf of Mexico. With a consistent analysis procedure in place, the database, populated with numerous treatments by engineers working throughout the GOM, can be analyzed objectively. The data contained in this database include rock mechanics, net pressures, pumping trend data, tip screenout (TSO) times, etc.
This paper explains the methodology and discusses the results of the database analysis, using case studies to determine the best method for analysis of the jobs. Crossplots show the correlation between TSO prediction and actual events and suggests recommendations for more successful future design work. This paper is meant to give up-to-date guidelines to help design better frac packs.
Formation Damage by CO2-Induced Asphaltene Precipitation
Authors: Okwen R. T. 
Published: December 2007

Abstract
To increase productivity from crude oil reservoirs, carbondioxide (CO2) is usually injected during secondary and/or tertiary recovery. While CO2 injection significantly increases the amount of oil recovered, it causes asphaltene deposition at high concentrations. However, the presence of water reduces the extent to which asphaltene is precipitated. Thus, the aim of this report is to determine why the presence of water reduces the amount of asphaltenes precipitated during CO2 injections. Results from CT scan data on water and gas injections are also provided and are accompanied with scanned images.