bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Management Using the Illinois State Geological Survey's Waterflood Database
Authors: Cokinos James S. , Huff Bryan G. , Frailey Scott M. , Seyler Beverly , Grube John P. 
Published: December 2007

Abstract
A digital database of the waterflooded oil reservoirs in Illinois was created as part of the DOE PUMP II program (Contract DE-FC26-02NT15132) to develop geographic information system-based (GIS) play portfolios to improve oil production in the Illinois Basin. The database was compiled from data on paper forms that are submitted annually to the Illinois State Geological Survey (ISGS) by petroleum operators. Attributes collected from the forms include annual and cumulative oil production, water injection and water production. Detailed oil reservoir information such as reservoir pressure, porosity, permeability, API gravity of the oil and depth of the waterflooded horizons are also submitted.
To help producers identify underdeveloped areas in existing oil fields, a strategy was devised and implemented to transfer the digital databases, data manipulation methods and GIS map layering capabilities to petroleum operators through an internet mapping server (IMS). Color coded pay maps and waterflood unit maps were used to identify horizons and units that are currently being waterflooded or were waterflooded in the past. The layering capabilities of the ILoil ArcIMS website could then be used by operators to locate potentially overlooked or bypassed reserves. This database should be available in late fall of 2004.
Using data available in the newly created database, we have used traditional waterflood and reservoir surveillance tools to compare oil reservoir responses in 3 Mississippian Reservoirs. The primary means for making comparisons between waterflooded units is the recovery plot and the recovery derivative. Representative decline curves and oil recovery curves are developed on a per unit/formation basis. These tools are designed to assist in a "first pass" assessment of individual waterflood patterns within a unit or a unit to unit comparison within a field.
Production Analysis of Coalbed Wells Using Analytical Transient Solutions
Authors: Pinzon Claudia L. , Patterson Joseph 
Published: December 2007

Abstract
Coalbed gas formations are an important part of the world's natural gas resource. The energy industry classifies these formations as "unconventional gas reservoirs" and is continually looking for methods to economically develop them. Engineers use various methods of computer simulation to predict performance of coalbed gas formations. There is a tendency to use numerical simulation to predict their performance because of the complex production behavior of coalbed methane wells in the early life of a well. However, reservoir simulation may not be practical for situations in which individual wells need to be analyzed rapidly8. One popular production analysis method is to analyze flowing production data using analytical techniques and type curve matching approaches. These analytical techniques are used to estimate reservoir properties from the matching of the historical data. In this study, public domain production data from producing U.S. coalbed methane basins has been used to illustrate analytical solutions and type curve matching for coalbed wells. The analyses include the use of analytical solutions for coalbed wells that take into account gas desorption from coal using isotherm data, analytical solutions for conventional gas reservoirs and Arp's decline curve analysis. It is assumed single gas phase, and that water production is minimal.
Field Application of New Lightweight Proppant in Appalachian Tight Gas Sandstones
Authors: Myers Roger , Potratz Jimmy , Moody Mark 
Published: December 2007

Abstract
Stimulation treatment designs must provide a delicate balance between completion effectiveness and economical viability. Service company research and development dollars have historically been spent to find the most cost effective treatment fluid for tight, gas-bearing zones. Typically, the focus of this research has been on fracturing fluids and viscous fluid proppant transport.
Thin banking fluids have been proven to be a cost effective fluid for tight gas zones in the Appalachian Basin, but significantly longer and more effective propped fractures are tough to achieve due to poor proppant transport. There are several factors that affect proppant transportation in a fracture, but one most often overlooked is proppant density. In a paradigm shift from focusing on fluid properties for proppant transport to focusing on proppant characteristics for proppant transport, recent technological advances have been applied as a solution for the Appalachian Basin's cost cutting – production enhancement dilemma. In several detailed case histories from New York, Pennsylvania, Ohio and Northern West Virginia, a novel lightweight proppant has been pumped in an effort to achieve the balance of a more effective fracture within tight economical constraints. The treatment effectiveness of the new lightweight proppant will be analyzed to determine if this new technology truly is a cost effective, production enhancing tool for one of the toughest basins to operate in based on well economics.
Stoke's Law calculations indicate that a lightweight proppant with a specific gravity of 1.25 g/cc will have a terminal settling velocity four times less than white Ottawa sand of the same mesh size, 20/40. A simple single phase gas simulator was used to determine initial flow rates and cumulative production for a series of different fracture lengths. It is clear from the simulations that if greater apparent acting fracture lengths can be achieved, flow rates will be increased and reserve-to-production ratios will be decreased.
Simple Field Compressor Automation Delivers Improved Production and Increased Efficiency
Authors: Cramer John W. , Moore Jeff 
Published: December 2007

abstract
Gas production decreases as gathering line pressure increases. Gas production from fields populated with plunger lift wells may be especially sensitive to increased gathering line pressures. One method of lowering gathering line pressure and improving gas production is to install field compressors. Gathering line pressure in fields utilizing field compressors may still fluctuate for various reasons beyond the control of the operator. Varying compressor speed can help stabilize the gathering line pressure normalizing and improving gas production. This paper will describe a project designed to investigate the effects and practicality of automating the speed control of field compressors.
Evaluation of a Depleted Gas-Condensate Reservoir for Gas Storage
Authors: Aminian K. , Brannon Alan , Ameri S. 
Published: December 2007

Abstract
A depleted gas condensate reservoir in the Appalachian Basin was considered for Gas Storage. Upon completion of the primary production, a retrograde condensate is present in the reservoir. When depleted gas condensate reservoirs are used for gas storage, gas injection will pressurize the reservoir and will re-vaporize the condensate. As a result, the produced gas during withdrawal cycle will contain heavy hydrocarbons which need to be removed by processing units so the gas does not form liquid phases by retrograde condensation in pipeline.
Peng-Robinson Equation of State (PR-EOS) was utilized to predict the liquid yield during storage cycle. The first step in applying PR-EOS was to simulate the primary depletion and check against the reported primary condensate yields. Upon successful history matching the primary production, the remaining retrograde and residue gas were mixed with pipeline gas to pressurize the reservoir to its original pressure. The fluids were assumed to be completely mixed. Since the volume percent liquid in the reservoir at the end of primary depletion is 5-10%, gravity drainage of the hydrocarbon liquid may be minimized. However, it is possible that the liquid phase can potentially be wetting the pore walls. This may interfere with the mixing and revaporization process. PR-EOS was then used to predict the liquid yield for several separator pressures. In addition, several cases without complete mixing were considered to study the impact of mixing on liquid yield. The results were then utilized for design of surface facilities.
HSE Training, Implementation, and Production Results for a Long-Term Underbalanced Coiled-Tubing Multilateral Drilling Project
Authors: Knight Jeff , Pickles Rob , Smith Bruce , Reynolds Mike 
Published: December 2007

Abstract
HSE training, implementation & production results for a long term underbalanced coil tubing multi-lateral drilling project.
The methods used to safely implement the bp Sajaa CT UBD project from start up issues through implementation will be discussed. To date, 14 wells have been drilled successfully with no accidents, the decline in the gas production for the Sajaa field has been mitigated and additional reserves have been accessed. This has been achieved through a programme of training, teamwork and service company integration leading to new heights of HSE performance for the industry. In addition, the key learning's have been carried forward from well to well to optimise the economics of the project and open up new opportunities previously thought to be unfeasible. Through a series of innovative engineering applications, the future of the project has been secured.
Reduction of Wellbore Effects on Gas Inflow Evaluation Under Underbalanced Conditions
Authors: Aremu O. J. , Osisanya S. O. 
Published: December 2007

Proposal
Wellbore storage effects have been identified to significantly smear the accuracy of evaluating reservoir productivity through the fluid outflow rate from the annulus during underbalanced drilling. Such effects have continuously introduced considerable errors in characterizing the reservoir during underbalanced drilling. Conceptually, due to the readily volume changing ability of the gas, wellbore storage becomes a determining factor during underbalanced drilling of a gas reservoir. Wellbore storage could either cause decrease (unloading effects) or increase (loading effects) in the annular gas density depending on the choke opening procedures. Correspondingly, annular fluid outflow rate is considerably affected. Since it is practically difficult to deduct the fluid flow rate due to the wellbore storage from the total fluid outflow rate, reducing the influence of wellbore effects on the evaluation of gas reservoir productivity is presented in this study. Volumetric production analysis at the wellbore-sand face is introduced through a mathematical modeling of inflow of gas bubbles into the wellbore. This mathematical modeling utilizes forces such as the viscous force, drilling fluid ejecting forces from the bit nozzles, buoyancy, interfacial tension, and gas reservoir forces for its analyses. Some analytical results that are overshadowed by wellbore storage are presented and supported by extensive experimental studies.
Use of Foamed Cement in Deep Water Angola
Authors: Benge Glen , Poole David 
Published: December 2007

Abstract
Increased activity in West Africa has improved the availability of many services and materials that were not readily available just a few years ago. Technologies that are commonly used in many parts of the world are now available. One technology used globally in deep water, foamed cement, has become readily available in Angola. Its use in deepwater applications has been shown to simplify well planning and logistics and has resulted in increased success and cost savings on current wells.
This paper discusses the introduction and use of foamed cement in deepwater cementing in Angola. Included is a discussion of logistics associated with foamed cementing and mobilization of crews, equipment and a comparison of this technology against alternate lightweight cement slurries. Discussed are the logistics for specialty-blended cements, including the need to import specialty cement materials or blends, excess inventories required to cover large contingencies and uncertainties, and associated delivery times. An analysis of the introduction of foamed cement to Angola is presented along with the associated risks of the use of both the foamed cement and alternate specialty slurries. On-location operational considerations for foamed cement are discussed and comparisons are made with the requirements for mixing of specialty lightweight slurries.
Proving UBD's Value in Brownfields and Beyond
Authors: Holt Calvin 
Published: December 2007

Abstract
Underbalanced drilling (UBD) is giving brownfields a new lease on life—while UBD technologies in development hold the promise of drilling the "un-drillable well" and reducing cost.
Much of the industry's mindset focuses on traditional drilling and stimulation technologies to exploit brownfields, but we suggest that in many cases the greatest potential for these reservoirs lies in UBD techniques. Emerging methodologies, like managed pressure drilling (MPD), are also moving rapidly into the driller's toolbox to allow him to "walk the line" between extremes in pressure regimes. Or perhaps technologies that reduce the cost of UB drilling and enabling underbalanced completions will be attractive enough to propel the technology across the ‘chasm’. This article discusses real benefits of UBD in mature fields and presents an overview of its new technologies in development.
Integration of a Performance Drilling Motor and a Rotary Steerable System Combines Benefits of Both Drilling Methods and Extends Drilling Envelopes
Authors: Rønnau Hans-Henrik , Balslev Peter Vilhelm , Ruszka Jon , Clemmensen Carl , Kallevig Sverre , Grosspietsch Ralf , Mader Georg 
Published: December 2007

Abstract
Since their introduction in 1997, rotary steerable drilling systems have delivered significant gains in drilling efficiency. In addition to this fundamental benefit, these systems have enabled more challenging wells to be drilled at low risk with a wide range of other advantages, including improved well placement, etc.
Continuous rotary drilling operations do however bring with them certain challenges which must be considered before rotary steering is selected for use. These include instantaneous penetration rate, specifications of rig rotary equipment, casing or drillpipe wear, stress on the drillstring, loss of drilling power through wellbore friction and drilling dynamics.
Using high powered drilling motors, traditional performance drilling has been applied since the early 1990's to improve penetration rates by applying high power and consistent operating parameters directly to the drillbit. This has however been limited to straight holes or the most basic of directional profiles.
A system has been developed which integrates a specially designed high power drilling motor within a high speed rotary steering assembly. By using this new system:
many of the challenges of continuous rotary drilling are mitigated, more complex wells benefit from the advantages of traditional performance drilling, existing drilling envelopes can be extended to further improve field recovery.
This paper discusses the engineering design of the complete system, including the specially designed motor and high speed rotary steering system. The paper then goes on to discuss specific applications where the system should be considered for use, illustrated with results from real examples.
Use of Pressure-While-Drilling Tools to Improve Formation Integrity Test Interpretation
Authors: Akers Jay , Sellers Jay 
Published: December 2007

Abstract
In deepwater drilling, a small margin usually exists between formation integrity and pore pressure. Accurate determination of the formation integrity at casing shoes is paramount to drilling an interval without losing returns. Non-aqueous fluid is often the fluid of choice for deepwater environments, and cold temperatures in the riser result in higher drilling fluid viscosity and gel strengths along with pressure and temperature effects on fluid density. These effects on fluid properties can induce inaccuracies in the interpretation of surface collected data when determining the fracture initiation pressure (FIP) during a formation integrity test (FIT). Downhole pressure technology can be used to more accurately determine fracture initiation during a FIT by measuring the true bottomhole pressure at the formation, thereby eliminating the effects of mud gel strength and varying mud weight in the mud column. The comprehensive pressure data, however, is stored in downhole memory and can only be accessed upon tool recovery or wireline data link. Neither of these options are economically attractive in the deepwater cost environment. However, limited downhole pressure data can be transmitted back to the surface once circulation is re-initiated. This paper presents a field useable method which makes use of limited real-time downhole pressure data to correct interpretation of surface collected data. This method has been compared to over 20 FIT results from actual downhole memory data and yields a close match.
Performance Drilling Onshore Iran - Introducing New Concepts to a Mature Area
Authors: Spoerker H. F. , Doschek M. 
Published: December 2007

Abstract
For a five-well exploration program, a brand new 2000HP onshore drilling rig has been imported from China into the Islamic Republic of Iran. At the time the project started (late 2003), this had been the first international drilling contractor entering into Iran since a brief attempt in 1991.
The wells have been designed to make full use of modern performance drilling, effectively introducing these concepts into an operating arena that has been characterized by almost complete isolation from developments in drilling technology for the last 25 years (since the Islamic revolution in 1979).
The paper presents the initial concept of how to drill these wells, together with the introduction of heightened environmental awareness during drilling operations, as well as the experience in implementing these concepts on the first well being drilled to 15000 ft in the Zagros fold belt onshore western Iran.
Solubility, Miscibility and their Relation to Interfacial Tension for Application in Reservoir Gas-Oil Systems
Authors: Ayirala Subhash C. , Sequeira Daryl S. , Rao Dandina N. 
Published: December 2007

Abstract
Miscible CO2 gas injection is becoming the most popular enhanced oil recovery process for light oil reservoirs in the world. An accurate determination of miscibility conditions is essential to improve the economics of these gas injection projects. The terms, miscibility and solubility, are widely used in phase behavior studies of ternary fluid systems. The distinction between these two terms appears to be still hazy, leading to their synonymous use in some quarters. Furthermore, the relation of these two properties with interfacial tension has largely remained unexplored.
Recently, a new experimental technique of Vanishing Interfacial Tension (VIT) has been reported in the literature, relating miscibility with interfacial tension for gas-oil systems. Therefore, the objective of this study is to correlate miscibility and solubility with interfacial tension and to investigate the applicability of the new VIT technique to determine miscibility compositions in ternary fluid systems. For this purpose, a standard ternary liquid system of benzene, ethanol and water was chosen since their phase behavior and solubility data were readily available. The interfacial tension of benzene in aqueous ethanol at various ethanol enrichments was measured in pendant drop mode, using the Drop Shape Analysis (DSA) technique.
The experimental results indicate the applicability of VIT technique to determine miscibility conditions for ternary liquid systems as well. Comparison of IFT measurements with solubility data showed a strong mutual relationship between these two properties, in addition to demonstrating a clear distinction between solubility and miscibility. This study has identified the need to use pre-equilibrated solutions for IFT measurements in soluble regions in order to eliminate compositional effects on IFT. The interfacial tension appears to be independent of solvent-oil ratio in feed, provided pre-equilibrated solutions are used during experimentation. The conceptual extension of these experimental insights to gas-oil systems at reservoir conditions would be of immense use in determining miscibility conditions for gas injection EOR projects.
Expandable Liner Installation Avoids Sidetracking Following Production Casing Failure in the Gulf of Mexico
Authors: Chustz Mark , Mason David , Schober Jamie , De Lucia Frank , Butterfield Chuck , Didyk Vladimir 
Published: December 2007

Abstract
During initial completion operations on a deepwater subsea oil well in the Gulf of Mexico, the 7-3/4 in., 46.1 lb/ft casing failed the pressure test in the production liner. Subsequent operations located the casing leak 1,800 ft above the target completion intervals. The original completion was planned to be a stacked, commingled frac pack with reservoir depths over 23,000 feet and pressures over 14,500 psi.
To best address the problem and maintain the original well objectives, a solid expandable tubular system was selected to isolate the casing leak. The first expandable cased-hole liner run in the well failed to initiate expansion and was recovered. Reviews, lab mechanical tests and surface prototype tests were conducted to determine the cause of the unsuccessful start and to plan a second run for casing remediation. The revised design deviated from standard equipment and used a shorter launcher with a smaller outside diameter (OD) and a closed-ended system. In addition to the equipment modifications, lessons learned from the first attempt influenced procedural changes for the second installation.
The second cased-hole liner run in the well a few weeks later was successfully installed and expanded. The ∼2,300 feet of expandable liner used eight elastomer seal anchor joints specifically located to isolate the leak and allow completion operations to resume essentially as planned. This installation was carried out with straightforward dimensional changes to the expansion system and revised procedures. The post-expansion dimensions of the liner enabled the completion of the well with a 7 in., 38 lb/ft equivalent inside diameter (ID) casing using standard completion equipment. At the time, this application set a record as the deepest cased-hole expandable liner ever run. The financial benefits of the installation included avoiding costs of drilling a risky sidetrack and production deferment.
This paper will discuss the problem on the first installation attempt, the operational response, subsequent recovery, lab tests and surface trials. The second installation will be covered in detail with an overview of completion operations and a brief outline of the value added through this expandable liner solution.