bluuebunny/crossref_metadata_2025 huggingface dataset:
Challenging Wellbore Cleanouts With Coiled Tubing Made Easy With Computer Modeling Technology
Authors: Nasr-El-Din H. A. , Al-Anazi M. A. , Balto A. A. , Proctor R. J. , Saleh R. M.
Published: December 2007

Well bore cleanouts have been performed for many years with coiled tubing and it may be said that the cleanout operation is one of the most routine services performed in the coiled tubing industry; but until recently design was no more than a rule-of-thumb approach. Sufficient information is now available to facilitate informed decisions and achieve reliable engineering solutions, utilizing a sophisticated particle transport model.

A methodical thought process, based on extensive research and mathematical modeling, will be presented for designing specific well bore cleanouts in a challenging offshore field in the Middle East. Case histories from a number of wells are documented detailing the conclusions from each. Laboratory analysis was performed on samples collected from the cleanout operations to further optimize and validate the design process. It is the intent of this paper to demonstrate the importance of sound engineering design, aided by comprehensive computer modeling technology.
Proxy Modeling in Production Optimization
Authors: Zangl G. , Graf T. , Al-Kinani A.
Published: December 2007

Proxy models are becoming more widely used as they can simplify highly complex processes with reasonable accuracy. Especially in risk analysis, where complex relationships between the uncertainty parameters exist, proxy models are used in form of response surfaces to accelerate interpretation and optimization methods. However, the use of proxy models is rarely seen in production optimization.

When the data gathering from wells and surface equipment is fully automated, production optimization can be performed almost in real-time. The bottleneck in this workflow is the high computational effort of simulation models and the large number of input variables to optimize. This disadvantage can be overcome by mimicking the behavior of the system, such as the coupling of a simulation model and the surface network model, by using a computational efficient method. The requirements for such proxy models are high, since they have to capture highly non-linear trends hidden in a small number of representative samples.

This paper presents the usage of neural networks as proxy models. For the production optimization process, genetic algorithms are used. Their advantage lies in the ability to handle a large number of input variables. The neural network operates as fitness function for the genetic algorithm. The optimization result can be achieved extremely fast (within seconds), allowing optimization in near real time. A real life example is also presented in this work.
Standalone Coiled-Tubing Water-Shutoff Operations Reinstate Well on a Normally Unattended Installation
Authors: Barclay D. A. , Lawson K. , Mullins B. , Cardno B.
Published: December 2007

The Amethyst B1D platform is a small normally unattended installation (NUI) in the southern sector of the U.K. North Sea. A coiled tubing (CT) intervention was required on well L04 during the winter because of gas contract demands and a combination of failures on production facilities and other wells. As this horizontal well had not produced since 1996, only limited well data was available.

This paper details the entire operation, from the choice of zonal isolation material (ZIM) and the equipment selection to the preparation for the multiple run CT intervention. The intervention design was tailored to operate within the operating environment of an installation with limited deck space, compact facilities, and only a 10-ton crane lift capacity. New equipment was manufactured and tested in the provision of this solution. Trials were performed onshore to optimize the rig up. Deck layouts, lifting, and boat loading plans were generated as a result of these trials. The rig up design was improved, and the equipment specifications were reviewed.

The basis of the actual intervention was to shut off the watered-out lower completion and isolate the unsupported annulus to prevent water from coning up from the toe of the well. This required the use of inflatable plugs and packers and the placement of a suitable ZIM. This paper details the knowledge gained during the planning, operational, and post job phases. This knowledge includes the importance that the logistical aspects provided to the intervention.

The well was put on production following the water shutoff operation and is now part of Amethyst potential.
Hydraulic Pump-Down Frac Plug and Subsequent Coiled-Tubing Removal Increases Client Efficiency in Barnett Shale
Authors: Blanton E. M. , Mackenzie G.
Published: December 2007

On average each well within the Barnett Shale play will produce from five (5) to ten (10) horizontal zones. Each zone is perforated and fractured with between 500,000 and 1,000,000 gallons of slickwater prior to isolation in order to repeat the process on the next zone. Previous to the methodology further described within this paper, the composite material frac plugs were deployed into the horizontal section of the wellbore by means of electric wireline and a tractoring system. While proving successful, this system did have limitations with respect to time and ultimately economics especially considering the average number of zones per well that required temporary isolation.

This paper will describe a system method improvement being utilized by most operators in the play whereby a Hydraulic Pump-Down Frac Plug is utilized. This cased hole temporary plug can be ‘displaced’ into the well at speeds of up to 200 feet-per-minute with surface pump rates of less than 10 barrels-per-minute. The BHA that is run consists of the Hydraulic Pump-Down Frac Plug, Wireline Adapter Kit, Wireline Pressure Setting Assembly, 2 sets of perforating guns and a firing head. After successful isolation and fracturing, the plugs are removed from the well bore in an under balanced environment by means of a coiled tubing milling assembly. The plugs have also been removed by reversing units utilizing 2-7/8" tubing and a 4-3/4" 5-bladed concave mill.

This paper will show how the development and use of this methodology has greatly increased the efficiency of completions within the Barnett Shale play by a potential reduction in time of 50% depending on the zone depth. The client costs have been significantly reduced not just in terms of time savings but also when the removal of the requirement for electric wireline with tractoring systems is taken into account.
Friction Factors for Two-Phase Fluids for Eccentric Annuli in CT Applications
Authors: Omurlu C. , Ozbayoglu M. E.
Published: December 2007

The gas-liquid flow phenomenon is frequently encountered during Coiled Tubing (CT) applications, especially in underbalanced drilling. In the wellbore, the flow takes place in more complex geometry than pipe flow. The determination of the pressure losses is the major concern prior to estimate the hydraulic system requirements as well as hole cleaning efficiencies and the drilling performances. The most commonly used mechanistic models are developed for two-phase pipe flow and the hydraulic diameter concept is generally applied to adapt the annular geometry to pipe flow. However, in case of two-phase flow through fully eccentric horizontal annuli, the complexity of the geometry couples with the difficulty of the physics of two-phase flow. In this study, friction factor correlations are proposed in order to calculate the pressure losses of two-phase systems flowing through fully eccentric annuli. The data used in this study, including pressure drop, flow rates, temperature and flow patterns, is obtained using the METU-PETE-CTFL multiphase flow loop. The collected data is analyzed and using statistical methods, friction factors are obtained both for considering different flow patterns as well as ignoring the flow patterns. The results showed that, the proposed friction factors for both methodologies could estimate the frictional pressure losses with an accuracy of less than 7% for all cases. The accuracy and the simplicity of the proposed methodology provide promising solutions to frictional pressure loss estimations of two-phase flow at the horizontal sections of CT.
Analysis of the Effect of Eccentricity on Flow Characteristics of Annular Flow of Non-Newtonian Fluids Using Finite Element Method
Authors: Ozbayoglu M. E. , Omurlu C.
Published: December 2007

One of the most difficult tasks in petrolum industry is to characterize the behavior of non-Newtonian fluids flowing through eccentric annulus. Many empirical and semi-empirical approaches have been introduced which attempt to solve this problem. Also, there are few analytical methods proposed, however, the performance of them were not promising. This study aims to approach the problem using finite element method (FEM), which became popular lately due to the developments of the computer technology. Defining a typical wellbore size commonly encountered in CT applications, three different non-Newtonian fluids were tested at three different eccentricities. Different FE mesh types were used to increase the accuracy of the results. The FEM results were compared with different conventional methods as well as experimental results which were available in the literature. The results showed that, as the eccentricity is increased, FEM can estimate the frictional pressure losses more accurately than conventinal methods. It is observed that, as the eccentricity is increased, frictional pressure loss is decreased, if all the other parameters are kept constant. Moreover, the velocity profile across the wellbore can easily be determined, which is very important to identify the hole cleaning performance of a fluid.
CT-Deployed Hydrajet Perforating in Horizontal Completions Provides New Approaches to Multistage Hydraulic Fracturing Applications
Authors: McDaniel B. W. , Marshall E. J. , East L. E. , Surjaatmadja J. B.
Published: December 2007

The application of horizontal completions in lower-permeability formations is continuing to proliferate on a global scale. Caused either by formation damage issues or the very heterogeneous nature of many such reservoirs, actual wells will underperform when compared to original predictions from reservoir simulations. This will continue to result in a need for effective hydraulic-fracturing stimulations for many of these wells to reach economic production levels. Horizontal completions in moderate- to low-permeability reservoirs present the challenge of cost constraints that seldom allow the use of long-proven methods such as cemented completions and individual-fracturing of numerous zones with bridge plug isolation and multiple perforating runs. Some new methods being applied to overcome this problem require expensive downhole "jewelry" and some added risks that the liner and jewelry can be entirely run to the predetermined depth. In some methods, the operator must also accept reduced completion IDs that can later restrict production rates or hinder workover operations. These increased costs and risks must be accepted even before the actual fracturing treatments are attempted.

This paper will discuss a new approach to controlled placement of multiple-stage fracturing treatments without the risks involved with packers or bridge plugs. By implementing a coiled tubing (CT) deployed hydrajet-perforating method, immediately followed by a fracturing treatment pumped down the annulus, the operator can use lower cost (and lower risk) liner completions, and delay the decision of selecting exactly where the perforated sections should be placed. In many cases, the final decisions on placement of the next perforated location can even be delayed until after the wellbore displacement of the preceding fracturing stage. By pumping the fracturing fluid slurry down the annulus of the CT and the casing the allowable frac rates can be higher than with tubing-deployed techniques. The total stimulation related costs are greatly reduced by being able to perforate/frac multiple times within the same day. Even where more than one day is required to complete the stimulation of all desired locations along the lateral, only one CT intervention and one pumping service company mobilization and rig-up will be needed, which will still improve the job economy over conventional methods. An additional benefit includes a reduction in the potential for excessive multiple fractures or near-wellbore tortuosity encountered with explosive charge perforating.
Eliminating the Human Error During Coiled-Tubing Operations
Authors: Burgos R. , Allcorn M. , Mallalieu R. , Vicens J. L.
Published: December 2007

In the last decade, several successful initiatives have been introduced to mitigate the risk of coiled tubing pipe failure while performing interventions in oil and gas wells. Through the use of reasonably accurate computer modeling, the industry has seen a marked reduction in the number of pipe failures associated with material fatigue due to the constant plastic deformation occuring during pipe tripping operations. Similarly, the judicious practice of employing off-line pipe quality inspection tools, as well as the availability of real-time monitoring of pipe geometry through a variety of devices has contributed to a more predictable and more favourable pipe performance.

A study of root causes for coiled tubing (CT) pipe failures over a five-year period indicates that a substantial percentage of incidents were attributed to human error. This type of incident involves the application of excessive overpull resulting in pipe necking or complete parting of the pipe due to tensile failure. Similarly, too much snubbing force will cause pipe buckling and compressive failure. Both have the undesirable result of a damaged CT string (at best) or a compromised well control security (at worst). Using a properly trained and fully competent crew can minimize such events. However, the ardous and stress-filled nature of live-well CT operations will limit the elimination of this human element.

This paper presents an effective means for eliminating the possibility of human error becoming a factor in conditions that could result in a pipe failure during normal CT operations. Through the incorporation of a specialized system in the coiled tubing unit controls, a safety device is put in place to provide a shutdown feature when specific job designed setpoints are exceeded.

This paper provides a discussion of the features and capabilities of such a system. It cites details of recent experiences demonstrating the benefits with use of the device in actual CT interventions.
Deployment of a Formation Dynamics Tester with Coiled Tubing
Authors: Herrera H. G. , Moreno A. , Maldonado R. , Dubost F. X. , Foinquinos C. I.
Published: December 2007

In their effort to continuously improve operations through the development of new and innovative technology, East Mexico operators have focused on optimizing operating times and reducing costs during the completion process by conducting in-situ characterization of gas fields. The challenges encountered when attempting to perform such tests are generally associated with the characteristics of the well completion, the length of open hole (OH) section below the shoe, the type of mud used and the high deviation profile.

These issues have prompted the design of an alternative coiled tubing (CT) conveyed technique. This paper presents the experience of the first deployment of a modular formation dynamics tester (MDT) on CT. This was used to perform several "point pressure tests" and achieve formation characterization of a gas well in the Lizamba Field, State of Veracruz, Mexico. With this new application, the operator was able to significantly reduce time and costs by performing the characterization survey following a conventional CT logging (CTL) operation.

The success of this technique has led to the enhancement of general OH CTL operations by the use of well control equipment at surface to provide formation characterization at slightly over-balance conditions. The greatest challenge is to have effective risk-mitigation procedures to avoid pipe sticking from differential pressure or problems with the small annular clearance between the tool and the wellbore. It has also been extremely important to have an effective contingency plan prepared to recover the toolstring if the stuck-pipe situation does arise.

This paper provides a discussion and analysis of these issues with reference to recent experience with CT- conveyed wireline tools in open hole.
Unique Coiled-Tubing Unit Design Improves Surface Efficiency for Performing Well Interventions in Algeria
Authors: Adil A. R. , Burgos R. , Howell R. L. , Samir A.
Published: December 2007

Various types of coiled tubing (CT) units have been in operation throughout the petroleum industry for over 30 years. Despite the introduction of desirable improvements in the quality of materials and components, the principle layout and operation of a coiled tubing unit (CTU) package has not changed much over time.

The geography of Algeria presents a very challenging environment for any oilfield operations. For example, less than favorable conditions exist from the extreme heat, hazardous routes must be traveled during equipment transport, restrictions in personnel movement are brought about by concerns involving security and local operating practices limit most of the operations to daylight hours only. To overcome these problems a light, efficient and fit for purpose CTU is needed. The CTU would have to be operationally efficient thus reducing the number of personnel to run and support the unit operation. This alone would minimize any potential safety issues by reducing the exposure of personnel to heat stroke and/or the handling and stepping hazards associated with rig up activities.

Using modern technology and a fit for purpose design of CT surface equipment, great improve-ments can be realized in safety, efficiency, reliability, and operating cost of CT operations. Since introduction to Algerian operations in 2002, a uniquely designed CTU has shown significant advantages over conventional unit designs. The equipment rig up process has been made safer and more efficient through improved design and the integration of various components. Process control of the whole well site operation allows the operator to focus on the down-hole treatment rather than surface logistics. A reduction in the number of trucks and personnel required to perform basic CT operations offers some significant efficiencies in operating costs.

This paper examines the facts and figures of this unique CTU in the Algerian area of operations including a comprehensive discussion of its features and why they have been beneficial in this challenging environment.
Well-Intervention Challenges to Service Wells that "Can Be Drilled"
Authors: Blount C. G. , Mooneyt M. B. , Behenna F. R. , Stephens R. K. , Smith R. D.
Published: December 2007

Drilling rigs are continually setting new records in measured depth versus true vertical depth ratios, horizontal section lengths, and delivering sophisticated versatile yet often operationally complex completions.

Experience suggests that common well intervention technologies including slick line, electric line, e-line tractors, Coiled Tubing (CT) tractors, pump-down services, and CT and CT enabling technologies may have difficulty fulfilling all the possible intervention needs of the wells that can and are being drilled and completed.

This paper will present an overview of available well intervention technology, outline limitations of each technology, and use numerous case histories from challenging interventions performed in Alaska to support the discussions and conclusions.
A Web-Based Integrated Project-Management System Supporting Teamworking and Decision Making on Field-Development Projects
Authors: Piantanida M. , Rossi P. , Gaudioso G.
Published: December 2007

Following the reengineering of ENI's Development Management System, which occurred in the early 2004, ENI has developed an IT integrated Project Management System to support Field Development Projects.

ENI's Development Management System promotes a stage&gate approach to the development of a field, starting from the assessment of the value of the field, the identification of the viable development scenarios, the definition of the selected development strategy and the execution of the project (including the construction of the facilities and the hand-over to operations). At the end of each stage, a predefined set of data and documents have to be prepared by the project team to be submitted to a Decision Gate in order to support an informed decision by ENI's executives and authorize the start of the following phase. The IT system has been developed with a Web Portal technology and it assists:

○ the multidisciplinary team involved in the project (geologists, reservoir and drilling engineers, facility & construction specialists, HSE consultants) in the daily work. In fact, it provides web based tools to share and verify project documents; develop and control the schedule baseline of the project; automatically track cost expenditures against budget values; document and review risks and lessons learned; manage milestones, issues and project changes; ○ the executives involved in decision making. In fact, it provides a high level dashboard with an integrated visualization of the last updated schedule and cost figures for the project, as well as direct access to the main project documents relevant for the Decision Gate of the current project phase.

The system integrates the document management capabilities of Domino; extends the planning and control functions of MS Project; automatically imports the budget/actual expenditures from SAP R3; authorizes and profiles users according to their role. It has been used to support 50 project phases across 34 projects.
Application of Global Optimization Techniques for Model Validation and Prediction Scenarios for a North African Oil Field
Authors: Griess B. , Diab A. , Schulze-Riegert R.
Published: December 2007

This paper presents a case study in which a Multipurpose Environment for Parallel Optimization is applied to assisted History Matching. Experimental Design techniques are used in order to investigate parameter sensitivities. Different global optimization methods are integrated into a workflow controlling a large number of reservoir simulations. For increased efficiency, simulations are run in parallel. Results are analyzed and compared to traditional History Matching to identify potential added value and increased efficiency. The reservoir engineer is in full control over the optimization process and interacts frequently with the History Matching process, while acquiring more information and improved understanding of existing uncertainties of the simulation model.

The history matching objective was defined to emphasize selected key wells where traditional history matching had proven to be difficult. The importance of a large number of input parameters was investigated, and an optimization scheme was set up to generate one or more alternative history-matched realizations of the simulation model. Alternative simulation models are determined by differences in model parameters as well as varying match qualities on a well-bywell basis. Selected results are used as input for alternative prediction scenarios.

The study was used to evaluate the economic potential for new infill wells, potential side-track locations and ESP candidates. The case study demonstrates the improvement in assessing reservoir uncertainties for an OMV-operated North African oil field. A structured process was implemented for assessing uncertainties related to oil in place volumes in selected regions of the field with a large impact on alternative prediction scenarios.
How Collaborative Environments Influence Culture and Behaviour
Authors: Williams P.
Published: December 2007

All companies are trying to produce organisational cultures that support their performance goals and growth aspirations.

This paper looks at how the increased connectivity afforded by the creation and use of collaborative environments can influence corporate culture by examining its impact on group dynamics and individual behaviours.

As well as looking at this inter-relationship, it also provides some advice on how to create these environments, including how to engage and enrol staff, and manage the transformation.

Finally a section is devoted to describing a Social Network Analysis tool that can benchmark and monitor the impact and effectiveness of collaboration.
CO2 Injection in Croatia: Revised Expectations for Ivanic and Žutica Oil Fields
Authors: Šunjerga S. , Domitrovic D. , Tuschl M.
Published: December 2007

First predictions of incremental oil recovery by CO2 injection at Ivanić oil field in Croatia (dating from year 2003) were based on laboratory data and a 3D simulation model matched against waterflooding history only. Since then, a field pilot CO2 injection was performed at Ivanić and the field data were used for corrections and modifications to the simulation parameters. A revised model of Ivanić field was used to generate more conservative recovery predictions. The same approach was then utilised for the pattern simulation model ofthe nearby Žutica oil field, a part of the same EOR project.
Permeability Modeling in Porous Media: Setting Archie and Carman-Kozeny Right
Authors: Haro C. F.
Published: December 2007

Archie empirical law is the basis of quantitative Petrophysics. The physical significance of this law is not well understood. This issue involves substantial uncertainty in oil in place.

Similarly, Carman-Kozeny (C-K) relationship is source of several permeability models. C-K is derived from Poiseuille equation, applicable in laminar viscous flow in straight non-communicating uniform tubes. Neither Poiseuille nor C-K formulae consider convective/inertial accelerations caused by changes in either cross section or flow direction. Implications include sizeable limitations in permeability modeling.

In this paper, appropriate hydrodynamic and electrical models are created using fluid mechanics analytical methods. The models delineate the velocity and electrical potentials, streamlines and controls, represented by C-K and Archie equations. This approach theoretically verifies both relations and demonstrates that:

Fluid circulation and permeability are optimally modeled invoking superposition of viscous and inertial regimes in nozzles, throats, diffusers, pipe networks, and arrays of solid particles. These hydraulic components, once assembled, emulate porous media well. Changes in fluid and electric flow direction are characterized by the flow around a corner solution of Laplace differential equation. The solution precisely defines rock frame, conductive phase, and hydraulic tortuosities, enabling direct ties to pore geometry. This facilitates permeability calculations utilizing the "perfect permeability transform" procedure.

Several experiments/examples are discussed to show validity. Some conclusions and technical contributions/applications are:

Electric measurements can predict hydraulic and petrophysical rock properties. Cementation exponent can be continuously computed employing acoustic tools and rock physics principles. Saturation exponent can be geometrically related to wettability and saturation using pore-scale modeling. A quantitative rock catalog can be implemented applying practical rock type definitions. Supported by these concepts, synthetic production logs can be generated to anticipate well performance, and to effectively assist in history matching. Archie law ceases being merely empirical. We gain a thorough physical understanding of its power law (fractal?) behavior. Rock responses can now be clearly explained and evaluated.
History Matching With Production Uncertainty Eases Transition Into Prediction
Authors: Little A. J. , Jutila H. A. , Fincham A.
Published: December 2007

The process of history-matching past reservoir performance involves making reasonable adjustments to key properties in a base geological model, either by ‘trial-and-error’ or using some computer-assisted approach, until observed data are adequately reproduced. Traditionally wells are controlled as individual entities and offtake rates that correspond to their historical allocations are imposed. This approach inherently assumes that there is no uncertainty in allocated well rates, and whilst a good match may be obtained, there is no guarantee that the resultant model will be robust in prediction.

It is frequently the case that a hiatus occurs when moving from well-rate controlled history-match mode to Group rate and well pressure (i.e. THP) controlled prediction, caused by wells exhibiting too great a potential – well PI's are typically adjusted to ‘correct’ this problem. This correction step is (a) time consuming (b) downgrades confidence in the relevance of the ‘match’, (c) reduces the predictive capability of the model, especially with regard to infill or new well production forecasting and (d) is different for each history match.

In this paper, a methodology is presented and illustrated whereby both static (geological) and dynamic (production allocation) uncertainties are addressed simultaneously during a computer-assisted search for multiple history-matches, which honour observed production performance and move into prediction without ‘correction’. Use of a Bayesian response-surface tool assists both in obtaining multiple matches and may be used to calculate statistically valid confidence intervals around predicted performance.
Tightness Testing of Environmentally Friendly Thread Compounds
Authors: Hoenig S. , Oberndorfer M.
Published: December 2007

In its most simple case the tapered round thread of casing or tubing is sealed by a thread compound i.e. a special kind of grease containing solids. To date, dopes that contain lead and other heavy metals, so called API-modified thread compounds, have found widespread use. This is surprising since metal free or even biodegradable thread compounds are available. OMV decided to initiate a project evaluating environmentally friendly thread compounds.

To find out which of the non toxic products have a good sealing performance, laboratory tests were carried out. Due to the lack of a standardised sealing tightness test for thread compounds a new benchmark test method was developed.

In the past, there have been two approaches for testing the "tightness" of the various thread compounds: the simplified grooved plate tests and the full scale tests on high pressurized and mechanically loaded pipes. Unfortunately, the plate tests do not provide reliable results, and the full scale tests are very expensive.

For the test described in this paper threaded pipes in small standard dimensions were used; relatively low testing pressures and no mechanical load were applied. Two parameters were implemented in a new way: temperature load and test duration. Temperature load was applied for the whole duration of the tests. The usual test duration was approximately two weeks but during the development phase some tests were run for several months.

This new combination of test equipment allowed inexpensive testing of many different thread compounds simultaneously. Not only performance differences between thread compounds could be examined, but also other relevant parameters such as varying temperature, pressure, torque etc. could be easily recorded.

After this new method had been refined seven environmentally friendly thread compounds were selected for testing, two of them being universal compounds. For reference purposes API-modified thread compounds from two different manufacturers were tested. Enormous differences in the sealing abilities of the products were found.

Life cycle costs can actually be reduced through the use of an inexpensive and effective thread sealing compound. Savings are possible due to a reduction in the number of workovers, of expensive down time and lost production.

It was clearly shown that some of the environmentally friendly thread compounds perform better and are cheaper than the old fashioned toxic API-modified compounds.
Technical and Economic Evaluation of Undersaturated Coalbed Methane Reservoirs
Authors: Carlson F. M.
Published: December 2007

Undersaturated coalbed methane (CBM) reservoirs will not produce commercial quantities of gas until the reservoir pressure drops below the critical desorption pressure (CDP) of the coal. Such undersaturated CBM reservoirs exist worldwide. Standard methods of technical evaluation involve coring and core analysis to determine gas content of the coal. Because these standard methods require coring and subsequent transport of the core to a laboratory for analysis, they are expensive. Added to the on-site expenses of core retrieval is the cost of deferred knowledge manifested in typically long laboratory desorption tests of the samples and the associated financial cost of obtaining the results in the laboratory. Furthermore, because of the nature of the coal, such analyses typically do not provide a measure of permeability, another essential variable needed in the economic assessment of a prospect. A new, patent-pending methodology allows more expedient, yet accurate, determination of CDP and gas content of the coal. This methodology is based on the concept that only the capture of a water sample, following some simple rules, and its subsequent analysis are all that is required to accurately estimate the CDP of the coal. Such formation-water analysis can be done on site through production testing; or, depending upon the situation, the water sample can be analyzed in a fluid properties laboratory. The specific property of interest is the bubblepoint pressure of the formation water, which is demonstrated here to be equivalent to the CDP of the coal. Experimental results for coals in Wyoming's Powder River Basin show that the method accurately predicts the pressure at which the reservoir will become capable of production of CBM. From the CDP thus determined and a measured isotherm (e.g., from a sample gathered from drill cuttings), or from an existing isotherm representative of the coal in a given area, one can accurately estimate the amount of gas contained in the coal. With this gas content and a measurement of permeability obtained from standard methods of well testing, an accurate and timely prediction of well performance can be achieved using generally accepted approaches such as CBM reservoir simulation or more simplified modeling approaches. This predicted performance can then be used to estimate the economics of the prospect.
Software-Assisted History Matching—A Case Study of a Very Constrained Problem With Extensive Pressure and Saturation Data
Authors: Ghedan S. G. , Gibson A. P. , Sener I. , Gunal O. E. , Diab A. , Schulze-Riegert R. W.
Published: December 2007

This paper presents a case study using a Multipurpose Environment for Parallel Optimization with application to assisted History Matching. Evolutionary Algorithms and deterministic optimization schemes are integrated into a workflow controlling a large number of parallel reservoir simulations.

The practical applicability of a software assisted history matching process is illustrated on basis of a real case study. The history matching process is discussed for an inverted 5-spot water flood pattern that had been subject to an extensive program of reservoir pressure and water saturation monitoring. Results are analyzed and compared to traditional history matching to identify the potential added valued and increased efficiency.

The quality of the manual history match was reproduced for pressure data and significantly improved for saturation data. The resulting model has proven to show better forward modeling characteristics defined by matching of some blind test data. Due to highly constraining boundary conditions defined by pressure and saturation data, it was not possible to generate multiple solutions to this specific problem. Within the given constraints, the model tuning parameters had to be close to the values of the reference case to be able to match such constraining pressure and saturation data.

In conclusion, the software assisted history matching process was able to improve the quality of the match within less time and effort. A lesson learned process is discussed focusing on the engineer acquiring more information and improving the understanding on reservoir uncertainties and the reservoir model behavior.
A New Mechanistic Model for Two-Phase Flow Through Eccentric Horizontal Annulus
Authors: Omurlu C. , Ozbayoglu E. M.
Published: December 2007

Multiphase technology is improving everyday in order to provide solutions for even most difficult design problems in most aspects of engineering. In drilling engineering, two-phase flow occurs during underbalanced drilling operations, especially in multilateral and extended reach wells. It has been a challenge for years to identify the flow patterns and predict the frictional pressure losses through circular pipes. Even less is known for annular geometries. In this study, a mechanistic model is developed in order to determine the frictional pressure losses occurring during flow through horizontal eccentric annular conduit. The flow pattern maps and estimated frictional pressure losses using the model are compared with experimental data gathered at METU-PETECTFL multiphase flow loop. The results show that model can accurately predict the flow pattern and frictional pressure losses for eccentric annulus. It is also observed that, the flow pattern boundaries for annular geometries differ from those for pipes having same hydraulic diameter.
Reservoir Characterization and Data Integration of Complex Mauddud-Burgan Carbonate Reservoir
Authors: Al-Bazzaz W. H. , Gupta A.
Published: December 2007

Mauddud-Burgan is a complex carbonate formation that contains substantial amounts of proven crude oil and runs south-east in Kuwait. It is a thin carbonate reservoir when compared to other Burgan reservoirs, which make it a candidate for horizontal drilling. The Mauddud reservoir offers about 40 feet of net oil-pay. It shows high porosity, about 18%, and a low matrix permeability between 0.8–10 mD. Several horizontal wells have been drilled, yet development of the Mauddud-Burgan program was abandoned due to the complexity of this formation. In 1994, only one well was a success and other nine were failures. Due to the structural complexity, prospect was less favorable than anticipated. With the world's demand for oil and the price of oil increasing, Kuwait Oil Company (KOC) is expected to be motivated to develop this reservoir.

The failed development of the past Mauddud-Burgan program involved a lack of understanding of this formation's complexity. Limited reservoir information for Mauddud- Burgan brought further development and planning to a standstill. This study proposes a detailed characterization of this formation to expedite future reservoir planning and development.

The proposed analysis involves seven aspects of reservoir characterizations which include: geological, thin-section, XRD, SEM, core, well logging, and, well test analysis. Core samples and data for the proposed studies were supplied by KOC, in co-operation with the Kuwaiti ministry of oil.

This paper reports results of several aspects of characterization, including geological and petrophysical analyses. The principal objective of the study is to integrate results manifested from experimental measurements of core samples and all other sources in support of a future development programs.
Correcting Underestimation of Optimal Fracture Length by Modeling Proppant Conductivity Variations in Hydraulically Fractured Gas/Condensate Reservoirs
Authors: Akram A. H. , Samad A.
Published: December 2007

A study was carried out to forecast the productivity of a hydraulically fractured well in a retrograde gas-condensate sandstone reservoir using a numerical model. The fracture was explicitly modeled as a set of high-conductivity cells.

At the gas velocities normally encountered in hydraulic fracture proppant packs, non-Darcy pressure drops dominate, and the apparent proppant permeability is one or two orders of magnitude lower than the Darcy permeability measured at single phase low-rate conditions. This is particularly true if a liquid phase is also flowing. The apparent permeability of the proppant is a function of: Gas velocity (hence: rate and flowing pressure)Ratio of free liquid rate to gas rateStress on the proppantType of proppant

Thus, apparent proppant permeability will vary with distance from the wellbore, increasing towards the tip of the fracture where liquid ratio and velocity are lower.

This variation of permeability was explicitly modeled in the proppant pack by dividing it into segments and calculating the permeability in each segment. As a result of this modeling, the impact of increased fracture length on productivity was found to be more significant than in simpler modeling where one permeability value is used for the entire proppant pack.

The variation of apparent proppant permeability along the length of the fracture and its impact on well productivity are discussed in this paper. A comparison of predicted well productivity is also made with the use of a constant permeability value for the proppant in numerical and analytic simulators. We will show that using a constant proppant permeability value results in an estimate of optimal fracture length that is too short.
A Gas/Condensate Reservoir Productivity Evaluation and Forecast Through Numerical Well Testing
Authors: Shi-Yi Z. , Marius N.
Published: December 2007

Well productivity impairment due to two-phase flow in the near well region is a major concern in gas condensate reservoirs. There usually exhibit complex flow behaviours due to the condensate banking around the well caused by the bottom-hole pressure drops below the dew point (for most gas-condensate reservoirs). This leads to a drop in gas relative permeability, a decrease in gas production and a significant economic condensate remains in the reservoir.

In this study, we use a methodology to evaluate the productivity of gas condensate wells. Starting from the analysis of six available well tests, we have identified one test that most suitable for the aim of this project. Then we have used a well-developed workflow in the Institute of Petroleum Engineering at Heriot- Watt University to carry out the study. The workflow is to first characterize the formation for reservoir heterogeneity, the fluid properties and well productivity to evaluate the well dynamic performance (transient pressure and inflow). The formation evaluation of the well is performed to determine key parameters of the reservoir. Then fluid PVT test results are studied in details for reservoir fluid property in contrast to the phase diagrams for the whole gas column. The nature of the test, i.e. a gas- condensate reservoir with respect to the testing depth, interval and pressure regimes (on the phase diagram) have been re-ensured.

A radial homogeneous model was built to tune the well test simulation local grid refinement cell sizes and time steps, and a 3D geological model was built using the latest techniques to honour the reservoir heterogeneity. The model was then up-scaled into a fully compositional flow model for well test simulation. Numerical well test has been conducted with the same testing schedule and parameters (rock and fluids) as the existing well test. Finally, sensitivity studies on key parameters have been performed through the numerical well test simulation leading to the construction of families of reservoir system type curves. By the matching of these type curves to the existing well test, a numerical model is derived by tuning and matching to the real testing data. The derived model then can be used for future productivity forecast, as well as for new testing design.

A well test interpretation completed in this way has greatly reduced the analysis uncertainty and enhanced the understanding of the testing and the reservoir providing much more value from a well test.
Development and Implementation of a Scale-Management Strategy for Oseberg Sør
Authors: Fleming N. , Ramstad K. , Eriksen S. H. , Moldrheim E. , Johansen T. R.
Published: December 2007

Oseberg Sør field, operated by Hydro Oil & Energy, is situated 130km west of the Norwegian coast on the eastern flank of the Viking Graben structure. It comprises a sequence of fault bounded structural units of varying geological complexity. Within these units the reservoir intervals are of moderate to poor quality and can exhibit strong contrasts in permeability and formation water composition. Reservoir support is provided by combined injection of gas and Utsira aquifer water. The wells are a combination of platform and subsea and comprise extended reach horizontals with complex geometry and lesser numbers of vertical wells.

Detailed scale predictions have been performed in order to identify the scaling risk for each producer. From this it was identified that the major risk to well performance and integrity was CaCO3 precipitation in the upper tubing with potential failure of the downhole safety valve. The risk varied from negligible to severe and reflected the variable composition of the produced water and well operating conditions. The scale predictions provided the basis for a technical and economic evaluation to identify an appropriate scale management strategy for Oseberg Sør. For those wells completed with downhole chemical injection lines the option to use these for scale inhibition was considered cost effective. In other wells where this option was not available, scale inhibitor injection into the gas lift system or squeezing using a viscosified treatment was considered viable.

The paper will provide the technical and economic reasoning for the scale management strategy selected along with field case histories for each treatment type (our experience with treatment using chemical injection lines, injection of scale inhibitor into the gas lift system and squeezing).
Review of Underground Gas Storage in the Bedded Salt Deposit in China
Authors: Guangjie Y. , Shen R. , Tian Z. , Yuan J. , Wang Q. , Yang M. S.
Published: December 2007

In view of the increasing importance of natural gas for China, especially when the West to east gas pipeline project started, Petrochina launched a study on constructing underground gas storage in the bedded salt deposit in 2000. The study was completed in the summer of 2005 after five years of work by experts from more than 6 countries. It provides information on new and emerging technologies, the status of gas storage in the bedded salt deposit, gas supply and demand, the geological evaluation and demands of salt caverns, the problems of caverns leaching, the reconstruction and utilization of existing salt caverns, gas injection and debrining, and so on. This report outlines the major aspects covered by the study, demonstrating some new viewpoints of underground gas storage in the bedded salt deposit. And now, 15 new salt cavern wells are constructing and 6 existing salt caverns have reconstructed by using some technology of this study.