bluuebunny/crossref_metadata_2025 huggingface dataset:
Information is Costly, but How Valuable is It?
Authors: Wills Hector A. , Graves Ramona M.
Published: December 2007

This paper presents a method for economic resource allocation for additional data acquisition using the value of information concept. To apply it, the basic condition is that at decision time the available information does not describe conclusively the state of nature. Consequently, the new information might lead to a change in the decision to be made because it has the ability to modify positively the prior perception about the state of nature. The maximum value of the new information comes from how well this perception, in probabilistic terms, is modified from its original value towards the probability of conclusive or perfect information value. The new information value is calculated before acquiring it; using Bayesian theory, with decision tree methodology in conjunction with Monte Carlo simulation applied to the estimated ultimate recovery (EUR) algorithm. A sensitivity analysis on the Bayes' conditional probabilty term is performed, and the results are presented in graphic form as the information surface, its 2-D projection and the Information index plot.

The model was built on spreadsheet based commercial software.
Self-Organizing Maps for Lithofacies Identification and Permeability Prediction
Authors: Stundner Michael , Oberwinkler Christian
Published: December 2007

Methods of Artificial Intelligence like Back-Propagation Neural Networks (BPNN) have become popular software tools to predict permeability and porosity from well logs during the last several years.

Similar to Multiple-Linear Regression models, Back- Propagation Neural Networks are trained with a set of target values from core measurements.

The Self-Organizing Map (SOM) Neural Network method applies an unsupervised training algorithm. Until now this approach has mainly been applied for clustering purposes only, not for predicting reservoir properties.

In a new application, SOM technology has been merged with statistical prediction methods to derive the following types of information from well logs and core measurements in one step: Synthetic lithofacies system (clustering)Porosity and permeability (prediction)

SOM technology also provides a data visualization tool which allows evaluating relationships between input variables (well logs) and output variables (reservoir properties).

SOM models can also be combined with BPNN in order to subdivide the entire set of well log patterns into different lithofacies and run individual BPNN models for each facies.

Application of this method showed increase in prediction accuracy and significant timesavings.

This paper should be viewed and printed in color.
A Unique Design for Deep-Set Tubing-Retrievable Safety Valves Increases Their Integrity in Ultra Deepwater Applications
Authors: Vinzant Mike , Vick James , Parakka Anthony
Published: December 2007

Tubing-retrievable safety valve (TRSV) performance has been improved drastically over the last decade as a result of simplified design concepts, increased use of non-elastomeric and metal-to-metal (M-t-M) sealing materials, and enhanced validation testing. Unfortunately, the demands imposed by deep-water applications have also increased, and in spite of continuing improvement in safety-valve technology, equipment continues to be pushed to its limits. Higher valve-opening pressures associated with deep-set applications have emerged, and to address these needs, conventional solutions have focused on balancing the wellbore and its reaction to the hydraulic piston area using mechanisms that require additional seals and/or gas-charged chambers. These solutions are heavily dependent on elastomeric seals and/or the permanent, long-term containment of a dome charge or pressure counterbalance, to maintain reliability. Unfortunately, dynamic elastomeric seals have posed a major limitation when design intent tries to focus on equipment that will provide life-of-the-well reliability.

This paper will review a unique TRSV design that is a revolutionary new concept. This design incorporates a floating-magnetic-coupler mechanism that allows the hydraulic actuator to be positioned in a dedicated chamber isolated from contact with well fluids and pressure. Since the hydraulic actuator has been separated from the tubing wellbore, this new valve is the first in the industry to have 100% M-t-M sealing with no moving seals within the tubing wellbore. The low hydraulic operating pressure of the valve also simplifies the complexity of the pressure source equipment and completely eliminates the need for high-pressure operating equipment. This is significant when considering both safety and cost; furthermore, it could completely eliminate use of high-pressure equipment and associated umbilical line, often more costly than the TRSV in a subsea application.

The new intrinsically simple design: Increases environmental and personnel safetyReduces system costsReduces sealing requirementsProvides an extremely reliable tubing retrievable safety valveIncreases life-of-the-well.
Improving Support Vessel Utilization on Subsea Operations Using Novel Underwater Pipeline Data Acquisition and Transmission Equipment
Authors: Johnston Neil , Sergeant Paul
Published: December 2007

During sub-sea pipeline commissioning operations using a surface support vessel, a substantial amount of non-productive time is endured during the hold period of pipeline hydrotesting. During this time, which may last up to several days, instruments on the support vessel monitor the pipeline pressure and temperature using long hoses and cables. The vessel is unable to move away and perform more productive operations elsewhere. In addition, adverse weather conditions may force the vessel to disconnect and move off station causing data loss and the requirement for a retest. With vessel day-rates in the tens, or even hundreds, of thousands of dollars per day, it is apparent that freeing the vessel during the hydrotest substantially reduces overall project costs and saves time.

This paper describes the development of an electronic sub-sea data acquisition and transmission system which achieves these goals by transmitting data to the surface using through-water two-way acoustic communications. Even if surface data collection becomes impossible due to the vessel moving out of range, or a deterioration in the acoustic environment, successful test verification is still possible as the data is permanently recorded in a non-volatile memory card sub-sea.

The paper also describes a number of challenges to successful acoustic data transmission in the offshore oil & gas marine environment. These include the naturally varying properties of the water column (water density, salinity, temperature and seasonal variations) as well as the relatively large horizontal displacement with respect to the shallow water depth (commonly found in many producing offshore fields) which lead to a heterogeneous acoustic velocity profile and multi-path effects. In addition, significant vessel-produced noise requires the use of advanced signal processing techniques to provide successful communications. It is believed that this technique could be applied to other sub-sea applications requiring remote monitoring & effective data acquisition.
Role of Critical Gas Saturation in Methane Production from Hydrate Dissociation at the Pore-Network Scale
Authors: Tsimpanogiannis Ioannis N. , Lichtner Peter C.
Published: December 2007

Hydrates are crystalline structures that are formed under conditions of low temperatures or high pressures and consist of a lattice made up of hydrogen-bonded water molecules, containing cavities. These cavities can be stabilized by van der Waals forces if occupied by certain types of guest molecules (e.g. CH4). Hydrates are very important compounds due to their capacity to store large volumes of gases. They are studied as a possible source of energy, since an enormous reservoir of carbon is deposited in worldwide accumulations of hydrates, containing predominantly methane, both on-shore (under the permafrost), and off-shore (in marine sediments).

In this study, a 2-D pore-network simulation based on concepts from Invasion Percolation in a Gradient is discussed to study the dissociation of methane hydrate in porous media. By using reported experimental values of porosity and permeability that are found in oceanic sediments we reconstruct a porous medium with similar properties by varying appropriately the size range of throat radii and the ratio pore/throat radii. The reconstructed porous medium can be either fully or partially saturated with hydrate. In this work emphasis is placed on examining the patterns formed by the release of methane gas in a partially saturated porous medium following hydrate dissociation. We investigate how the various patterns are affected by parameters such as the viscous pressure drop applied to the system, the size range of throat radii, hydrate saturation, and pore size distribution. Note that in order for the methane gas to be produced from the system, the critical gas saturation (defined as the volume fraction of the gas phase at the onset of bulk gas flow) must be reached. This is an issue of significant importance that delineates the possible range of parameters where methane production can be economically viable. For the critical gas saturation to occur the produced gas clusters must: either (i) connect to each other forming a sample-spanning gas cluster through which the gas phase can be produced, or (ii) be mobilized by the presence of viscous or buoyancy forces and thus arrive at the producing end of the network (this is a limiting case where continuum models may break down because of the formation and mobilization of gas bubbles). In order to obtain a better understanding of the production efficiency for the commercial development of hydrate deposits we address the significant question whether the resulting dissociating system (at lower hydrate saturation values) is below or above the critical gas saturation and how the aforementioned parameters affect the value of the critical gas saturation.
High-Resolution Near-Wellbore Modeling and Its Applications in Formation Testing
Authors: Liu Wei , Hildebrand Margaret A. , Lee Jaedong , Sheng James
Published: December 2007

Formation Testing (FT) can collect high-resolution data sufficient to capture small variations in fluid and formation properties. Unfortunately, conventional interpretation techniques are rarely capable of processing the data from complex tool configurations and formation properties. Studies have shown that numerical simulation can replicate the complex physics of multiphase fluid flow but often not at the level of detail needed for high-resolution data interpretation.

In this paper, we propose a general three-dimensional and multiphase numerical model to incorporate various wellbore and/or tool factors. Unlike the analytical source representation of a well commonly used in reservoir simulation, the proposed model establishes the internal boundary of a well, generally involving the pressure and flow rate at the sandface, where the size of the wellbore or tool configuration is equivalent to or smaller than that of the grid cells. This fully coupled and fully implicit model at a fine spatial and temporal scale is advantageous in revealing further potentially useful information and realizing the synergy across a spectrum of FT applications. As a result, wellbore and/or tool factors, particularly the tool storage effect, can be integrated at a level of detail not previously possible in the absence of a comprehensive wellbore model.

The mathematical formulations and numerical schemes are presented. Simulation studies include the primary FT applications in the field, i.e., pressure transient testing and fluid sampling for both oil-based and water-based mud filtrate. These examples show that the proposed near-wellbore high-resolution modeling approach with non-negligible wellbore and/or tool factors permits new insights into fluid flow in FT applications.
Improved Reservoir Simulation With Seismically Derived Fracture Models
Authors: Ouenes Ahmed , Zellou Abdel M. , Robinson Gary C. , Balogh David R. , Araktingi Udo G.
Published: December 2007

History matching and simulation of naturally fractured reservoir is a recurring challenge to many oil and gas companies seeking to manage and develop fractured reservoirs. Several techniques have been applied in the past to match past production and pressure history that have been proven unreliable. This paper describes a methodology to improve the simulation of fractured reservoir using seismically driven reservoir characterization.

The methodology presented in this paper uses the integration of geophysical, geologic, and engineering data simultaneously to improve the reservoir description. At the root of the reservoir characterization lays the more and more accurate seismic data collected on most of the reservoirs around the world. The initial use of this seismic information is made possible through high-resolutioninversion and spectral imaging. These two processes allow a better imaging of key reservoir properties that have an important impact on fracturing. Based on this seismically driven reservoir characterization, the reservoir properties necessary as inputs to the reservoir simulator, i.e. fracture porosity and permeability, are generated using artificial intelligence tools and core measuremenst as fracture indicators.

The usefulness of the derived seismic attributes is illustrated on a specific reservoir where a new well was recently drilled. The drilling results indicate that the derived seismic attributes can be used successfully to locate highly fractured areas. Using the generated seismic attributes in an integrated fracture modeling approach allows for a better modeling of the "plumbing" of the reservoir through a correct estimation of the fracture permeability and porosity. These improved fracture properties lead to a history match of the well performances. Examples of such history matches are given for illustration purposes.
Case Studies in Production Optimization Using Chosen Information Sources and Information Technology
Authors: Leshchyshyn Tim , Rieb Brad
Published: December 2007

Well data for oil and gas wells drilled in the Western Canadian Sedimentary Basin (WCSB) exist in many places and multiple formats with ranging detail. Multiple data sources, both internal and external, are needed to optimize the well stimulation and the production optimization process. Public production and well data in the WCSB is considered high in quantity and quality for reservoir description. This data repository exists due to royalty and tax reasons and is strictly enforced by government legislation. Unfortunately, detailed completion data are not part of the public database records. However, companies whose core business include drilling and completion field services usually keep a comprehensive and detailed collection of data. These pumping service companies often have data that are unavailable in the public databases.

This paper outlines the first steps in developing a synergistic approach to integrating publicly available production and well data with detailed completion data from private sources. The case study presented shows the effectiveness of combining internal detailed completion data with external third party data.

Case study #1 evaluates various fracture fluid systems and size on production in the Medicine Hat gas of southeast Alberta, Canada. Case study #2 evaluates stimulations in the Horseshoe Canyon Coal Bed Methane (CBM), fairway in south central Alberta, Canada. Production impact of current industry stimulation practise and some alternatives are examined.
The Tengiz Field History Matching Problem Revisited
Authors: Gao Guohua , Zafari Mohammad , Reynolds A. C.
Published: December 2007

The limited memory Broyden-Fletcher-Goldfarb-Shanno (LBFGS) is an ideal optimization algorithm for large-scale automatic history matching problems. In previous work, we applied the LBFGS algorithm to condition a model of the Tengiz reservoir generated from static data to buildup pressure data at 44 wells. The resulting reservoir model displayed regions of extremely high and low permeability values inconsistent with the geologic information. Here, we identify a potential source of this problem, and present an approach which yields a history-matched model that is consistent with the geological/geostatistical model.
A New OCTG Strength Equation for Collapse Under Combined Loads
Authors: Klever F. J. , Tamano T.
Published: December 2007

Wells are becoming more challenging and casing designers are faced with increasing design pressures. Deep hydrocarbon targets lead to requirements for the casing to resist collapse under external pressure while significant internal pressure and axial compression or tension may exist at the same time.

This paper describes the development, and its evaluation, of a new collapse strength equation for oil country tubular goods (OCTG). It is based on a generalization of a model previously proposed by Tamano et al.1. The new model is evaluated through comparisons with both finite element analyses and test data. It is more accurate in dealing with combined internal pressure, external pressure and axial load than, for example, the model currently provided in API Bulletin 5C32.

The joint API/ISO SC5 Work Group 2B tasked with modernizing the API 5C3 property equations has evaluated a number of collapse models available in the literature on their performance against several different collapse databases. As a result the model presented here is recommended for developing collapse ratings in the new ISO 10400 standard.
A Method for Continuous Interpretation of Permanent Monitoring Pressure Data
Authors: Ramakrishnan T. S. , Raghuraman B.
Published: December 2007

We show that a pressure pulse originating in a well is correlated to a pulse observed at a distant well with a characteristic time. The correlation time is directly related to the diffusion time scale arising out of the pressure diffusion equation. The relationship is affected by the source-observer or observer-observer distance but the correction is small for large distances. In practice, further corrections have to be included for finite width pulses. For these pulses, we present a practical scheme for continuous permeability monitoring.

Wellbore storage also has a strong influence on the correlation time-scales. We show a simple forward calculation that removes this effect and allows a direct estimation of reservoir scale permeability. The techniques developed in this paper are simpler to practice than conventional interference testing, and do not require the same level of periodicity or uniformity of pulses.
Up-Gridding from Geological Model to Simulation Model: Review, Applications and Limitations
Authors: Fincham A. E. , Christensen J. R. , Barker J. W. , Samier P.
Published: December 2007

In recent years, several papers have presented methods for choosing an optimal coarse grid suitable for dynamic simulation, given a multi-million cell geological model as starting point. Usually these methods include some technique for measuring how well the coarse simulation grid represents the response of the original fine scale grid.

In this paper, we describe a software package we have produced based on these methods. We discuss some of the difficulties encountered in applying the published methods to realistic reservoir models. We present our experience in using the methods in real case studies, both successfully and otherwise. Finally, we discuss the limitations of this type of approach to up-gridding.
High-Accuracy Wet-Gas Multiphase Well Testing and Production Metering
Authors: Atkinson D. I. , Reksten Ø , Smith G. , Moe H.
Published: December 2007

Dedicated wet-gas flowmeters are now commercially available for the measurement of gas and liquid flow rates. They offer a more compact measurement solution than the traditional separator approach. The interpretation models of traditional multiphase flowmeters emphasize the liquid rate measurements; they have been used to well test and meter mostly liquid-rich flow streams. These models were not developed for the measurement of gas flow rates, particularly those of wet gas.

A new interpretation is described that allows a traditional multiphase flowmeter to operate in a dual mode either as a multiphase meter or as a wet-gas meter in 90% to 100% gas. The new interpretation model was developed for a commercially available multiphase flowmeter consisting of a venturi and a dual-energy composition meter. This combination results in excellent predictions of the gas flow rate, and in addition, liquid rate and water-cut predictions are made with an acceptable accuracy with no additional measurements.

The wet-gas and low-liquid-volume-fraction interpretation model is described together with the multiphase flow meter. Examples are presented of applying this model to data collected on flow loops, with comparison to reference flow rates. The data from the Sintef and NEL flow loops show an error, better than ± 2% reading for the gas flow rate, at line conditions; the absolute error in the measured total liquid flow rate at line conditions of was better than ± 2 m3/h (< ± 300 bpd).

This new interpretation model offers a significant advance in the metering of wet-gas multiphase flows and yields the possibility of high accuracies to meet the needs of gas-well testing and production allocation applications without the use of separators.
Faster, Deeper, Cheaper – Slimhole Well Construction in the Gulf of Thailand
Authors: Hibbeler Jeff , Seymour Richard , Rae Phil
Published: December 2007

The 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

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

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

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

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

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

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

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

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

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

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

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.
Damage Interpretation of Properly and Improperly Drilled Underbalanced Horizontals in the Fractured Jean Marie Reservoir Using Novel Modeling and Methodology
Authors: Kimery Dave , van der Werken Theo
Published: December 2007

The Jean Marie reservoir in the northeastern part of British Columbia, Canada, is one of the most active horizontally underbalanced drilled reservoirs in the world. The Jean Marie is a depleted, low permeability, fractured carbonate with low initial water saturation making it susceptible to formation damage using conventional drilling fluids.1 Given these reservoir characteristics, horizontal underbalanced drilling is the current method of choice for operators active in the area.

Although underbalanced technology has made tremendous improvements in maintaining and ensuring underbalanced conditions at all times during operations, overbalanced incidents do occur while drilling the horizontal section. These incidents can be much more damaging than drilling with a well designed overbalanced fluid. In some cases, an overbalanced event could permanently impair production from a well by as much as 75%.

With the aid of real time downhole pressure gauges, these overbalanced incidents can be identified but very often go undetected, leading to a false sense of achieving the goal of minimal damage. The unidentified damage can lead to misinterpretation of production results and disappointment with underbalanced drilling.

To exacerbate the problem of identifying damage, traditional pressure transient analysis of wells in the Jean Marie may yield incorrect valuation of the overbalanced incidents by underestimating the skin on the face of the horizontal well. This could be due to the difficulty of performing meaningful transient analysis on a horizontal well in a dual porosity reservoir and a general lack of knowledge of the impact of drilling related damage on fractured or highly heterogeneous reservoirs.

This paper will show how, by combining transient productivity index data collected while drilling with the use of history matching techniques, overbalanced incidents can be easily identified and the impact on well productivity can be quantified.