bluuebunny/crossref_metadata_2025_split huggingface dataset:
Faster, Deeper, Cheaper – Slimhole Well Construction in the Gulf of Thailand
Authors: Hibbeler Jeff , Seymour Richard , Rae Phil 
Published: December 2007

AbstractThe Kingdom of Thailand is a net importer of both oil and gas. However, over the years a successful plan to boost local production has made the country less dependent on foreign imports. The many side benefits of this include, cheaper power generation for the Thai economy and the development of secondary downstream markets. One of the drivers for Thailand's success has been the commitment to new technology and continuous improvement employed by local operators and service companies. In fact, the role of technology in the generation of economic value within the Thai oil and gas industry cannot be overstated. This can clearly be seen by the systematic improvements made to the well construction of a market considered marginal only thirty years ago. One major step-change came in the early 1990's with the advent, and subsequent refinement of, slimhole drilling. This combined with the massive "batch-drill" concept has transformed this market into a thriving business.Several unique geologic and reservoir conditions in the Gulf of Thailand (GOT) account for this extreme technical and economic condition. A few of these issues are: small compartmentalized reservoirs with highly complex geology, multiple stacked pay sands, extremely high temperature gradient, relatively low pressure gradient, fast production declines, water breakthrough, high CO2 content of gas, and high mercury content of the oil.Improvements in all aspects of drilling played a role in the refinement of slimhole well construction1,2,3,4. Cementing has also kept pace and is one of the most important aspects of well construction and production. In the upper hole sections cement jobs need to be as logistically simple as possible and be must provide support to drill ahead quickly. In the GOT slimhole model, production tubings are cemented in place making the cement job an integral part of the completion. Indeed, one can think of the cement job as a very long production packer.This paper describes the cementing innovations achieved in the GOT within the context of the overall well construction effort. Also presented is a brief look into the future of drilling and cementing of slimhole wells.
Review of Sand Control Results and Performance on a Deep Water Development - A Case Study from the Girassol Field, Angola
Authors: Delattre Eric , Authier Jean François , Rodot François , Petit Gérard , Alfenore Jacques 
Published: December 2007

Abstract
Wells in the Girassol field, offshore Angola, are situated in very deep water and are being completed in unconsolidated sandy turbiditic reservoirs. These conditions have brought about significant challenges for well completions in this field: while the expectations in terms of production rate are high, the completions must be reliable and cost effective. Today, 28 wells have been completed and connected to production facilities. This field has been producing since December 2001.
The choice of sand control techniques was a question much debated at the early stage of the project due to the different points of view on the subject among the partners. The completion strategies employed to date have included mainly sand alone screens in open hole and cased hole frac-packs.
This paper will provide an overview of the Girassol field, and a report on the current situation after two years of high rate production. It presents an assessment of the different sand control techniques based upon well tests and production results along with PLT's and reservoir interpretations.
The paper will also describe the design for both injectors and producers, along with the criteria in place today related to the sand characteristics, and off-shore implementation of the completions.
Development as the Continuation of Appraisal By Other Means
Authors: Laughton D. , Laughton David , Bratvold R. B. , Begg S. H. , Campbell J. M. 
Published: December 2007

Abstract
This paper is part of an overall programme to investigate how to distill the massive amounts of technical information that are generated in the analysis of any upstream petroleum asset into suitable formats for use in "complete" decision tree analyses of the design, management and value of that asset. A complete decision tree analyses future flexibility in response to all dynamic uncertain variables, including prices, throughout the life cycle of the asset. The first part of the paper explains how and why we have set up this programme. The second part of the paper begins an examination of a particular issue where we need to distill technical detail for use in a complete decision tree.
The upstream petroleum asset life cycle is usually divided into discrete phases. However, the actual situation is more fluid. For example, information arrives, and can be collected, throughout the life of the asset. In this sense, appraisal never stops, and, in principle, development and production activities should be tuned to take into account the value of the information that can be collected as a result of these activities.
We begin to explore this by examining, in an integrated fashion, the appraisal and development phases of the asset life cycle, using a model of an offshore oil-field development lease as an example.
We presume that drilling and facilities construction are the only two activities during this part of the life cycle.
Drilling can give information about the asset ("appraisal drilling") or provide production capability ("production drilling") or both.
Investment in production facilities begins at sanction, which can occur in any year until the end of the lease.
In our initial exploration of this issue, we have found situations where an asset manager can add value by considering the option to have mixed appraisal and production drilling programmes before and after sanction.
Coupled Flow Simulation in Coalbed Methane Reservoirs
Authors: Guo Xiao , Fu Yu , Du Zhimin , Shu Zhuangzhi 
Published: December 2007

Abstract
Coal seams are characteristic of two distinct porosity systems: macropores and micropores, similar to fracture systems and matrix systems for fractured hydrocarbon reservoirs. Since coal is relatively impermeable, any coalbed methane (CBM) recovered usually must flow through existing fracture systems helping increase the flow rate of CBM, which may induce CBM non-darcy (N-D) flow when high CBM rate. During CBM depletion, the deformation effect of coal skeleton may also have considerable influence upon CBM flow. Although there are a number of CBM reservoir simulators that have been available for many years, to our knowledge, almost commercial-scale CBM simulator have not provided the features of N-D flow and coal skeleton deformation. In this presentation, a coupled flow model in CBM reservoir, accounting for N-D flow effect and coal skeleton deformation effect, was presented. The mathematical model was numerical solved by differential discrete and the implicit format treatment method. Based on our in-house gas-water simulator developed before, a simple coupled flow simulator in CBM reservoirs was developed. The technique uses an explicit algorithm to couple CBM flow and the changes of porosity and permeability of coal seams where flow calculations are performed every time step and the changes of porosity and permeability of coal seams are calculated only during selected time steps. Sample simulations are conducted to compare with the differences in influence of N-D flow effect and the coal skeleton deformation effect upon CBM production behavior. The results indicted the decreased in coal seams porosity and permeability can reduce the CBM rate and recovery much than N-D flow effect. Unfortunately, porosity and permeability of coal seams are constant in almost CBM simulations, as often assumed. The work recommended the alteration of coal seams porosity and permeability should be considered globally to correctly predict the CBM rate and recovery.
Development and Implementation of a Low-Polymer-Concentration Crosslinked Fracturing Fluid for Low-Temperature Applications
Authors: Cramer David D. , Woo George T. , Dawson Jeffrey C. 
Published: December 2007

Abstract
Low-temperature fracturing applications are considered here to be those in which in-situ reservoir temperature is insufficient to facilitate fracturing fluid degradation (e.g., about 200°F or less.) In these cases, careful consideration must be given to fracturing fluid and gel breaker design to mitigate post-treatment clean-up problems while still providing for significant viscosity development throughout the treatment. Recently, improved manufacturing processes have led to the introduction of processed enhanced guar (PEG), enabling significantly reduced polymer concentrations to be applied with specialized cross-linked guar-borate formulations. These so-called PEG systems have led to enhanced fracture clean-up while achieving excellent proppant placement in the fracture.
Design and Feasibility of Creating Gas-Storage Caverns by Using Acid to Dissolve Carbonate Rock Formations
Authors: Castle James W. , Bruce David A. , Brame Scott E. , Brooks Donald A. , Falta Ronald W. , Murdoch Lawrence C. 
Published: December 2007

Abstract
The feasibility of creating gas-storage caverns by dissolving carbonate rock formations was examined based on process design, geologic factors, and preliminary economic analysis. The method involves drilling one or more wells, pumping acid into the formation, and then removing and treating the waste fluid. To enhance acid transport into the formation, the rock may be hydraulically fractured prior to pumping the acid.
To analyze the requirements for creating storage volume, the following were examined: weight and volume of rock to be dissolved; gas storage pressure, temperature, and volume at depth; solubility of acid-rock reaction products; and acid costs. Design considerations and economic calculations indicate that the new method will be applied most advantageously to carbonate formations deeper than approximately 4000 feet, with limestone at depths between 6000 and 9000 feet preferred. In order to identify potential sites for applying the new method to creating storage volume, a large amount of data from carbonate formations was compiled for six states: Ohio, Kentucky, Indiana, West Virginia, Pennsylvania, and New York. Based on GIS analysis, large areas of West Virginia, Pennsylvania, and New York were identified as potentially suitable for developing carbonate-cavern storage. Smaller areas that may be suitable were identified in Indiana, Ohio, and Kentucky.
The potential for application of this new method is very promising based on preliminary economic analysis that considered capital costs, well-design options and costs, waste treatment options, and cost comparison with other gas storage methods.
Effect of Reservoir Properties on the Performance and Design of Gas Storage Wells
Authors: Bilgesu H. I. , Ali W. 
Published: December 2007

Abstract
Natural gas plays an increasingly important role as a clean energy source. The demand for natural gas changes seasonally and the desired storage reservoir should be capable of meeting the peak rates especially during the winter months. There is a need to develop more gas storage reservoirs that are managed efficiently. The inherent problem is the maximization of production with minimum cost. The maximum production is a function of gas volume controlled by the reservoir properties such as porosity, permeability and pressure. It is beneficial to determine the optimum combination of wells, cushion gas, and compression facilities to minimize the cost of developing a new gas storage reservoir or converting an existing gas or depleted oil reservoir.
Many factors affect the capacity of a gas storage reservoir, and to find the best combination is a challenge. A limited improvement of formation properties can be achieved by stimulation treatments. On the other hand, decisions regarding the number, location, and type of wells, completion methods, hole size and similar decisions are the result of proper planning.
In this paper, we present the results of study conducted to investigate the reservoir properties and their impact on the completion strategies for fractured gas storage reservoirs. A main goal of this study is to optimize natural gas production from fractured formations. Presented in this study are the effects of reservoir properties on the efficiency of selected well design to meet the demand.
Multizonal Isolation Technology for Injection Testing and Stimulation Treatments
Authors: Broussard John , Haiek Alejandro , Wilson Stuart 
Published: December 2007

Abstract
As the responsibility of R&D spending in the oil field shifts to service companies, many new technologies are introduced as tools. Combining multiple tools or processes can present new and exciting answers to old intervention challenges.
This paper describes coiled tubing operations using a newly developed straddling system on two particular wells that were producing from several perforated intervals. The key to both operations was to first isolate each zone, perform injectivity testing at varying flow rates, and then to stimulate each zone at a rate below fracture pressure. The initial challenge was the large number of zones—16 zones in the first well and 14 zones in the second well—leading to the requirement to have multisettable technology in order to complete the individual zonal treatments in as few runs into the well as possible. The second challenge entailed the need for accurate depth control to ensure the zones were correctly straddled to allow for optimum treatment. If the packer elements were not set in the exact place, the treatment could be misplaced. A wireless casing collar locator (CCL) with pump-through capability, contained as standard within the tool, was used, delivering accurate, real-time depth readings without any added limitations or further runs in the well.
Inflatable technology was preferred over the conventional mechanical-cup isolation because of subsidence in the area and casing integrity concerns. Based on laboratory testing of the two reservoir types, two chemical systems were selected for the stimulation treatment; one was hydrofluoric clay acid-based and another xylene-based. Both chemicals are known to be chemically aggressive to the conventional rubber seals and elastomers found in inflatable technology. It was imperative that the inflatable could withstand these chemicals for the treatment to succeed. Multiple setting of the tool was completed by using flow pattern recognition devices in the tool. Sending individual pumping sequences from the surface through the coiled tubing to the tool accessed the different modes alternating between inflation, injection, circulation, and deflation mode. A feedback signal from the tool was received at the surface as a confirmation that the tool had correctly actuated to the desired mode.
A real-time correlation log was created; the inflatable packer was multiset on depth, injectivity testing took place and the clay acid- and xylene-based stimulations were pumped into all zones. The multiple technologies were combined in an innovative application that met all objectives of the operation.
Optimizing Turbodrill Designs for Coiled Tubing Applications
Authors: Seale R. , Beaton T. , Flint G. 
Published: December 2007

Proposal
The uses for coiled tubing (CT) have expanded over the last two decades to encompass more broad based applications than ever before. This coincides with advancements in drilling technology that have extended these applications to deeper depths, in more hostile environments, the drilling of more complex well profiles, and CT drilling at shallower depths. CT technology has had to keep pace in order to perform effectively in workover operations, and in drilling operations such as sidetracking, wellbore extensions and grass roots drilling, in these more hostile environments.
Technology has been adapted to CT as it has been required. However, in many instances, these adaptations have fallen short of achieving optimal performance. The use of Turbodrills is a prime example of this unrealized potential. Using Turbodrills in CT applications provides many benefits, but, historically, a standard Turbodrill, configured for drilling, has been taken off the shelf for use on CT. This method can and has been successful. However, by analyzing the specific applications encountered with CT, Turbodrill design enhancements can be made to better match the Turbodrill to CT applications. One major advancement in this area, is the creation of a Turbodrill that can provide more power with a shorter tool. This paper will detail the design enhancements made to the Turbodrill to accomplish the goals of establishing a shorter tool, with more power, to address current and future applications.
Type Curves for Coalbed Methane Production Prediction
Authors: Aminian K. , Ameri S. , Bhavsar A. , Sanchez M. , Garcia A. 
Published: December 2007

Abstract
Coalbed Methane (CBM) currently accounts for nearly 8 percent of U.S. annual gas production and approximately 12 percent of estimated total U.S. natural gas reserves. Coalbed methane proven reserves in the United States have increased from 3.7 Tcf in 1989 to 18.5 Tcf in 2002. This number is expected to increase even further as more resources are discovered and a better understanding of the existing resources is achieved. Appalachian Basin accounts about 10 percent of U.S. CBM resources. However, CBM production is very limited in the Appalachian Basin. The contribution of CBM to overall mix of natural gas sources in U.S. is expected to increase for next two decades. However, this cannot be achieved without substantial increase in CBM production in the Appalachian Basin. The problems causing the lag in development of CBM in the Appalachian Basin need to be overcome for CBM to reach its true potential in the U.S. energy equation.
Gas production from CBM reservoirs is governed by complex interaction of single-phase gas diffusion through micro-pore system (primary porosity) and two-phase gas and water flow through cleat system (secondary porosity) that are coupled through desorption process. In order to effectively evaluate CBM resources, it necessary to utilize reservoir models that incorporate the unique flow and storage characteristics of CBM reservoirs. These models are often complicated to use, expensive, and time consuming. The typical gas producers in the Appalachian Basin suffer from the lack of scientific, user-friendly tools that can assist them in development of CBM resources. Therefore, it is necessary to develop tools that make it possible for typical (small to medium size) producers to seriously consider this important resource.
This study presents a set of production type curves that would help the producers to predict the production from their CBM wells. As a consequence, the producers would be able to make better, more informed decisions regarding the CBM resources in the region. A reservoir model that incorporates the unique flow and storage characteristics of Coalbed Methane reservoirs was employed in this study to develop the type curves. The type curves provide a reliable tool to predict the production performance of CBM reservoirs both during dewatering and stable gas production phases. The application and issues concerning the production performance of CBM reservoirs are also discussed.
Case History—Devonian Completions in North-Central West Virginia Using Integrated Reservoir Analysis Improves Field Production
Authors: Rodvelt Gary , Paugh Rodney , Snyder Steve , Chapman Dan , Shreves Judson , Grogg Kenny 
Published: December 2007

Abstract
Devonian Sands in north-central West Virginia can have as many as 13 productive intervals. Because of the high treating pressures on fracturing jobs, placing designed sand loads into some of these formations can be difficult. Recently, fracturing designs required improvement in these areas to successfully stimulate the reservoir while remaining within economic constraints. Improved analysis of digital log data coupled with reservoir-production review has resulted in improved completion designs, and stimulation engineers are now able to optimize fracture designs for each of the identified primary zones. The authors present past completion practices followed by the new completion designs and show the increase in production achieved. Recommendations for further improvements are also made for future West Virginia operations.
A Safe Approach to Underbalanced Drilling in an H2S Producing Field Leads to Operational Success and Productivity Improvement
Authors: Coy Alejandro , Hall Don , Vezza Matt 
Published: December 2007

Abstract
Located in West Texas, the Yates field was discovered in 1926 and is one of the largest oil reservoirs in the United States. Its shallow reserves have been accessed mostly with vertical wells but, over the last few years, implementation of a horizontal well program has significantly affected the overall production performance of the field. The reservoir energy of the field is maintained by Nitrogen (N2) injection into the gas cap and field-produced water injection below the oil leg. Low reservoir pressure and highly productive rock in both the gas cap and the water zone present challenges to drilling operations whether underbalanced or conventional. These conditions caused wells drilled previously by conventional methods to incur severe lost circulation upon encountering a fracture system. This resulted in premature suspension of drilling operations and a consequent failure to achieve the desired lateral lengths
One such well had been prematurely terminated after using conventional drilling practices that resulted in massive losses and posed the risk of stuck pipe. It was selected as a candidate well for a pilot project to evaluate the use of underbalanced drilling techniques (UBD) using a close loop system with high pressure separation. Through proper planning, the use of UBD allowed the operator to increase the horizontal length of this well and significantly increase its production potential.
This paper discusses the well design and the underbalanced modeling considerations (taking into account detailed reservoir properties), which led to the extension of the existing horizontal leg to intersect additional fracture sets without losses, resulting in a significant production increase. The paper also describes the process used to address HSE issues of the project in the face of the potential presence of high surface levels of H2S while drilling. The drilling and production results that were achieved were significant to the future operational potential and viability of this mature field. Of equal importance was the success of the operation from a health, safety and environmental (HSE) perspective considering that the field has a 4 percent H2S producing gas cap, an environment in which the industry has been traditionally reluctant to use UBD techniques.
Utilization of Underbalanced Drilling Techniques to Exploit a Low-Pressure Reservoir in Indonesia
Authors: Pickles Rob , Brand Pat , Savage Pat 
Published: December 2007

Abstract
A seven well Big-Bore Underbalanced drilling and completion program was undertaken under challenging downhole conditions in a low pressure, high permeability carbonate reef reservoir in Indonesia. Underbalanced drilling technology was utilised as conventional drilling practices were no longer viable due to the extreme low pressure (1.1ppg e). UBD was selected as it would eliminate lost circulation and stuck pipe problems, reduce formation damage, eliminate the need for post drilling stimulation and give early analysis of reservoir behaviour and production rates. The resulting wells incorporated the largest tubingless gas completions in the world and were completed in an undamaged state, resulting in 29% higher than anticipated initial gas production rates.
This paper will describe the Front End Engineering Design, Project Management, Risk Mitigation, Detailed Engineering & Design, Operational Results and Lessons Learned for this project.