bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cased-Hole Pseudo-Density Logging to Distinguish Clinton Sandstone From an Associated Non-Reservoir Carbonate
Authors: Holsclaw Steven S. , Martin Jason G. , Rubin William L. 
Published: December 2007

Abstract
Columbia Gas Transmission operates a 290-well underground gas storage field in north-central Ohio. The Weaver storage field, converted to gas storage starting in 1937, utilizes the Silurian-age Clinton sandstone as the storage reservoir. Clinton sand thickness, reservoir quality, areal distribution and lateral continuity are often highly variable over short distances. Many of the storage wells have only cased-hole electric logs, primarily a gamma ray with an API neutron. Stratigraphic correlation and identification of Clinton sand members can be problematic, particularly when relying on cased-hole logs and original completion records.
Compounding the task of Clinton sand correlation in the northwestern portion of the Weaver storage field is the depositional presence of "Red Rock", an iron-bearing carbonate identified through x-ray analysis as an Ankerite [Ca(Fe, Mg, Mn)(CO3)2]. Over ten square miles of Red Rock with a thickness of 10 feet or greater have been isopach-mapped. Historically, the Red Rock presents a clean, blocky gamma ray signature on electric logs with an associated neutron response similar to a gas-filled sandstone reservoir. In portions of the Weaver storage field, the Red Rock was often miscorrelated as Clinton sand and mistakenly completed in numerous wells. This resulted in an undesired division of the hydraulic stimulation between Clinton reservoir sand and non-reservoir rock. Also, due to a significant iron presence, completion acids may have reacted negatively when exposed to the Red Rock to produce iron precipitates that can degrade well performance. Accurate correlation of both Clinton sand and Red Rock carbonate, therefore, is crucial to the operational success of Weaver storage field.
To address this problem in cased-hole workover candidates, a pseudo-density logging technique was used in conjunction with an API neutron log with considerable success. This logging methodology could have additional cased-hole applications where contrasting behind-pipe porous sand with associated or enveloping carbonate is desired.
MudCap Drilling When? Techniques for Determining When to Switch From Conventional to Underbalanced Drilling
Authors: Medley George , Stone C. "Rick" 
Published: December 2007

Abstract
Throughout the planning and hazard analysis phases of unconventional drilling techniques, one question continues to arise: When is it appropriate to switch from conventional drilling to underbalanced operations?
The one condition that must exist before choosing an underbalanced operation is first encountering a need for the application of the technique. That the problem cannot be solved using conventional, less expensive means must also be determined. In many fields with no historic use of underbalanced techniques, one or more attempts to solve the problem utilizing conventional techniques are carried out until those methods are shown to be ineffective.
When the appropriate conditions have been satisfied, several other criteria exist that affect the decision to make the switch from conventional circulation to underbalanced methods, including Safety, Economics and Logistics.
Using data and examples from MudCap Drilling (MCD) scenarios from around the world, this paper demonstrates the process and techniques that have been utilized to successfully determine when the critical point has arrived to make the switch.
The development of a simple flow chart that can be utilized at the field location in making the determination to switch based on satisfaction of pre-determined criteria is also demonstrated.
Work and presentations to date have concentrated on answering the questions of ‘Why’ and ‘How’ to perform various underbalanced operations, with very little emphasis on ‘When’ to perform the underbalanced operation. While this answer is often self-evident, in many cases there is substantial leeway in determining what conditions should be present. This is particularly true when the "Why" has no bearing on preventing formation damage.
The Relationship Between Petroleum Economics and Risk Analysis: A New Integrated Approach for Project Management
Authors: Lewis Derrick , Guerrero Victor , Saeed Saad , Marcon Michael F. , Hyden Ron 
Published: December 2007

Proposal
Generally, today's oil and gas projects are complex, high-risk, multidisciplinary ventures that require careful planning and precise implementation. A large number of interrelated factors and unforeseen (operational, technical and/or financial) events determine a drilling, completion, or work-over project's economic feasibility and ultimate success. Fundamental to the success of all project management is extensive economic modeling and risk analysis, since economic drivers and operational methods are developed from these processes.
This paper will discuss the development of a new analytical technique that will systematically and intuitively overcome the hurdles mentioned previously while not compromising result sophistication. A variety of underbalanced drilling examples will illustrate its efficiency. This method will allow the end user, whether novice or expert, to quickly and effectively assess economic feasibility and risks.
Bottomhole Pressure Control During Pipe Connection in Gas-Dominant Wells
Authors: Nygaard Gerhard H. , Vefring Erlend H. , Fjelde Kjell Kåre , Nævdal Geir , Lorentzen Rolf Johan , Mylvaganam Saba 
Published: December 2007

Abstract
To obtain an underbalanced pressure condition, nitrogen gas can be injected into the drillstring. Simultaneous injection of liquids and gases leads to a highly dynamic flow system. During pipe connections, pressure transients can cause the bottomhole pressure to rise above the pore pressure of the reservoir or fall below the reservoir collapse pressure. Migration of gas during pipe connection and in-flow from the reservoir will also cause bottom-hole pressure changes.
This paper presents a methodology for controlling the bottom-hole pressure during pipe connection in gas dominant wells. The methodology incorporates a dynamic model of the well fluid flow and the well-reservoir dynamic interaction. Available control actions during the drilling process are the gas injection rate prior to the pipe connection and choke valve settings during the pipe connection. Measurement of the pump rates, pump pressures, choke pressure and the bottomhole pressure are also available to support the control actions. However, during pipe connections and in the event of transient signal failures, the bottomhole pressure measurements will be suppressed.
The control methodology used is based on a non-linear model predictive control system, which predicts the near-future behavior of the well, and uses these predictions to obtain the optimal choke settings and pump rates. The model parameters are calibrated using measurements from the well, to ensure that the model is suitable for the predictions.
A field based case with gas injection has been examined using this control methodology. The results indicate that model based control can be utilized in developing an automated and integrated pump rate and choke control system for underbalanced drilling operations.
Underbalanced Drilling as a Tool for Optimized Drilling and Completion Contingency in Fractured Carbonate Reservoirs
Authors: Abdollahi J. , Carlsen I. M. , Mjaaland S. , Skalle P. , Rafiei A. , Zarei S. 
Published: December 2007

Abstract
Maintained pressure management and fracture network mapping are key issues for successful well construction in fractured carbonate reservoirs. Prediction and characterization of the fracture network prior to drilling is very difficult and challenge optimized well direction and placement in respect to the fractures. Avoiding productivity impairment by loss of drilling fluids is another major challenge.
Later stimulation of a micro-fractured reservoir invaded by drilling mud is extremely difficult or even impossible. Open hole completion is generally preferred in these type of reservoirs. Underbalanced drilling (UBD) is therefore an interesting option for enhanced data acquisition, avoiding reservoir impairment and achieving completion contingency for optimized well production and added value.
Locating and characterizing the natural fractures while drilling is a vital issue for appropriate well placement and selection of completion options during the field development strategy. Depending on the opening and extension of the fractures, the mud loss rates and volumes can differ from low to heavy. The associated fracture network is the main parameter contributing to well production.
Underbalanced drilling is one of the main recommended technologies for further development of fractured carbonate reservoirs in South-West Iran. Flow drilling, allowing the hydrocarbons to flow to surface while drilling, will be advantageous. With sufficient reservoir pressure, this method enables better fracture characterization and a dynamic decision process can be applied for drilling horizontal wells with optimized well trajectory intersecting more fractures. Formation damage can be avoided and dramatically reduce unsuccessfully drilled wells.
Technical Feasibility and Applicability of a Concentric Jet Pump in Underbalanced Drilling
Authors: Suryanarayana P. V. , Hasan ABM Khalid , Hughes W. James 
Published: December 2007

Abstract
We examine in this paper the feasibility of using a concentric jet pump to create an underbalanced condition while drilling subnormally pressured reservoirs, using only single phase injected fluids, eliminating the need for gas. A complete technical basis for the performance and design of jet pumps for underbalanced drilling applications is presented. The problem is handled in four parts: reservoir to jet pump suction, the jet pump itself, annular flow from jet pump exit to surface, and power fluid flow. Multiphase flow theory, viscous flow theory and jet pump flow theory are used to analyze the problem. The design goal is to find the correct combination of jet pump location, geometry, power fluid density and rate such that the jet pump exit energy is adequate to lift the mixed fluids and solids to surface. Other design considerations such as tolerance of varying reservoir conditions and depth, cavitation, sonic velocity limitations, and power fluid injection pressure constraints, are also taken into account in the design procedure. Jet pump design envelopes unique to its application in underbalanced drilling are developed to aid selection and design of the pump. A design program that implements the procedure has been developed. The procedure is illustrated with two examples: an oil well and a gas well. We find that the jet pump can successfully create an underbalanced state for a wide range of conditions. In general, for reservoir pressures in the range of 4 to 7 ppg equivalent, the jet pump appears to enable creation of an underbalanced condition without requiring injected gas, regardless of whether the reservoir is oil bearing or gas bearing. Operational and practical considerations that need to be addressed in proving the design are also discussed. Based on this work, we conclude that the concentric jet pump is a unique device technically suitable for a wide range of uncerbalanced drilling applications.
Practical Use of a Multiphase Flow Simulator for Underbalanced Drilling Applications Design – The Tricks of the Trade
Authors: Mykytiw C. , Suryanarayana P. V. , Brand P. R. 
Published: December 2007

Abstract
This paper focuses on practical use of a multiphase flow model for design of underbalanced drilling (UBD) applications. Since most UBD operations involve multiphase flows, UBD operations are synonymous with multiphase flow modeling. Once a candidate well has passed requisite reservoir valuation and screening criteria, the next step is to establish the technical feasibility of the technology and determine the key operational parameters including equipment specifications. Multiphase flow modeling is an essential part of this process, and as will be detailed in the paper, influences all aspects of design and construction of an UBD well.
By definition, the goal in underbalanced drilling is to maintain a pressure below pore pressure along the entire open hole section that is targeted for UBD. While a drawdown is indeed desirable, there is clearly an upper boundary dictated by wellbore stability and/or coning of undesirable phases. The UBD operational envelope is further bound by adequate hole cleaning performance through proper design of the circulation parameters. The conditions that satisfy these underbalanced parameters should also consider limitations of the bottom hole assembly (BHA) components, in particular motors/MWD, and realistic in regards to the injection criteria (rates and pressures). Finally, multiphase flow modeling over a range of conditions, including sensitivities and safety factors, allows the sizing of the surface equipment (with maximum reservoir inflow considerations), and thus implicitly influences the design of the entire UBD operation.
The primary purpose of this paper is to describe the strategy of effective multiphase modeling for UBD including modeling sequence and necessary sensitivities, to ultimately deliver a "robust" design. Reservoir uncertainty is the primary culprite to flow modeling flaws. Moreover, due to the relatively simplistic user interfaces on complex multiphase flow engine software, the results of the model may be misinterpreted. It is through an accepted modeling strategy that this risk is manageable. Although the design example employs a single commercially available simulator, Wellfo 7, the interpretation principles could be adopted with any "acceptable" industry model.
The Challenges of Numerical Simulation of a Complex Fractured Carbonate Reservoir with Available Disparate Data Sets
Authors: Iwere F. O. , Apaydin O. G. , Moreno J. E. , Nogaret C. 
Published: December 2007

Abstract
This paper presents the challenges of constructing adequate static and flow models of a field from disparate data sets, and the workflow methodologies adopted for integrating, reconciling, and extrapolating available data from multiple disciplines. This study uses a data set of about 300 wells penetrating a 2500-meter thick section of fractured and vuggy carbonates. A 30-year production history was used to calibrate the model; the main recovery mechanism of the complex is rock and fluid expansion, combined with a weak aquifer.
A reservoir simulation study was constructed to investigate the field behavior under natural depletion, water injection and gas injection, and to provide technical foundation supporting investments in future development projects. The static model comprises of a three-dimensional structural model, a matrix property model, and a fracture property model. There was no 3-D seismic. The complex system of normal and reverse faults dividing the structure into 70 fault blocks was created from well picks. The matrix property model was derived from limited routine and special cores, and vug analysis. The fracture property model was obtained by integrating fracture indicator logs, including DSI, image logs, conventional logs of different vintages, with fault orientation from structural conditioning, core analysis, PTA, well production and static pressure histories.
The complex structure, long production history and the various recovery mechanisms posed additional challenges in constructing and calibrating the flow models to historical performances. The fluid properties for the thick reservoir sections were derived using limited available fluid samples, and verified by history matching reservoir pressure and gas-oil ratio, which declined over time until secondary gas cap encroachment. The different vintage and accuracies of the pressure and rate measurement devices were also considered in evaluating the history match quality.
A Simultaneous Water and Gas Flood Design with Extraordinary Vertical Gas Sweep
Authors: Stone Herbert L. 
Published: December 2007

Abstract

Proposal
This paper describes a new secondary oil recovery method that will make the world’s producible petroleum reserves last decades longer. It makes water and WAG pattern floods passé. Its novel element is a unique completion configuration for simultaneous water and gas injection in a pattern flood. The gas is injected through one site located near the bottom of the formation, and the water is injected through a second separate site located directly above the first. High-rate water injection in the upper part of the formation greatly impedes the vertical upward flow of gas, causing it to finger horizontally far into the reservoir before flowing upwards. This mode of simultaneous injection can give a 3-4-fold greater vertical gas sweep of the formation than does WAG, the alternate injection of water and gas into a single completion interval. Such a flood can be initiated at any time in the life of a field, including after complete depletion.
When combined with the use of horizontal wells, the new approach is effective even in thin reservoirs. Also, calculations for a Prudhoe Bay-similar reservoir indicate that an additional recovery of 5 million barrels of oil above WAG recovery can be recovered from each 80-acre pattern, using the existing vertical wells
Injecting gas along with water gives higher oil recovery than water flood alone, because the presence of residual gas saturation at the end of a flood results in lower residual oil saturation than would result from a water-only flood. If the gas miscibly displaces the oil, the water-gas residual oil will approach zero. Even for gases that are completely immiscible with the oil, a number of investigators have found the residual oil after a water-gas flood to be in the range of 0-50 % of the water flood residual, in water-wet and intermediate-wet reservoirs. These studies lead to the conclusion that both miscible and immiscible gases are effective in lowering the residual oil in a water-gas flood. However, there will likely be many reservoirs for which the cost or lack of availability of the miscible fluid will make immiscible gases more economic than miscible ones.
An approximate quasi-steady state reservoir simulator was developed and used to identify this superior mode of gas and water injection. Transient simulation could not be used for this purpose because of the numerical dispersion (truncation error) inherent in it. The quasi-steady state simulator is validated by a favorable comparison of its solution to one resulting from a finely gridded transient reservoir simulation. The two methods yielded very nearly the same quasi-steady state shape and size of the gas-flooded zone. The gas saturations in constant saturation zones established by the flood were also matched.
Variation of Fracture Opening with Pressure -- Key to Well Productivity in Naturally Fractured Reservoirs
Authors: Du Y. , Guan L. 
Published: December 2007

Abstract
Naturally fractured reservoirs usually developed many scales of fractures, for example, the super-high-permeability flow in big fractures, mid-permeability flow in small fractures and very-low-permeability flow in matrix rock. This results in the subsurface multi-scale flow during the reservoir development. This multi-scale flow makes it tougher to analyze the well productivity than that of a conventional reservoir. In this paper, muti-rate well-testing data were used to calculate the production capacity at different reservoir pressures in naturally fractured reservoirs. The method is exemplified with two wells in a case reservoir. The calculation results are very similar to field production data. We conclude that oil production rate in these kind of reservoirs is not only impacted by both two-phase flow and non-Darcy flow as in conventional reservoirs, but also impacted by the variations of fracture opening. This conclusion can be used to better define the optimal rate for the reservoir under different reservoir pressures, thus further improve our forecast accuracy and overall field development results.
Simulation Investigation of Casing Eccentricity Estimation for Different Inclination Angles and Tensile Forces Using Finite Element Method
Authors: Akgun Ferda , Al-Ghadban Hamed H. 
Published: December 2007

Abstract
Casing eccentricity has been considered as a problem during design and calculations of primary cementing, particularly in inclined and horizontal wellbores. Engineering calculations are usually based on the assumption of concentric annuls, which usually leads to erroneous or at least inaccurate results. One of the major problems of primary cementing is improper displacement of cement slurry around casing in the annular space. This often leads to gas channeling I gas wells, which consequently necessitates expensive squeeze job. Therefore, it is important for accurate engineering designs to use actual eccentricity values and not a concentric casing assumption in the derivations and application of used equations. This requires accurate eccentricity estimation.
The ambitious objectives of this study are to estimate the casing eccentricity at inclined section of a directional well as a function of hole inclination angle, applied tension, and measured depth. To achieve these goals, a two-dimensional finite element method (FEM) was used. Furthermore, the influences of inclination angle, casing length, and tension force on the calculated values of casing eccentricity are investigated. Casing lengths of 102, 204, and 300 ft from the bottom of the hole with different inclination angles of 15°, 30°, 45°, 60°, 70°, and 90° were modeled under different tensile forces i.e., 0, 20000, 40000, and 60000 lbf., respectively.
The results indicate that increase of inclination angle increases the casing eccentricity. The inclination angle has a major effect on the casing eccentricity when it is between 0° (vertical hole) and 30° (inclined), and change in effect when it is between 45° (inclined) and 90°(horizontal).
The results also showed that as the applied tension force increases, the casing eccentricity decreases. Furthermore, it is concluded that the casing length has no effect on the calculated values of casing eccentricity.
The attained results of this study provide more understanding of the role of casing eccentricity with respect to hole inclination and tensile force. Furthermore, it may have a real impact on well borehole cleaning, casing design, and cementing hydraulics of inclined/horizontal wellbore holes.