bluuebunny/crossref_metadata_2025 huggingface dataset:
Detection of Water or Gas Entries in Horizontal Wells From Temperature Profiles
Authors: Dawkrajai P. , Lake L. W. , Yoshioka K. , Zhu D. , Hill A. D.
Published: December 2007

The temperature profiles in a horizontal oil-producing well can be measured precisely with distributed temperature sensors, which are being increasingly installed in intelligent well completions. With temperature resolution on the order of 0.1 °F, modern temperature-measuring instruments can detect small temperature changes along the wellbore that can indicate the locations of water or gas entries into an oil well. These temperature changes are primarily caused by differences in Joule-Thomson effects for each phase (oil, water, and gas) caused by the pressure drop in the well.

In this paper, we illustrate a specific condition for which water entry locations can be identified from the temperature profile of a horizontal well. The criterion for such discrimination is that a measurable change in the slope of the temperature profile occurs at the water entry location. Using a numerical model of temperature and pressure in the reservoir and the wellbore, we calculate time-varying temperature profiles for a bottom water drive reservoir. In these calculations, one section of the well was experiencing a large flow rate, while the rest of the open section of the well produced oil at a smaller rate. We varied the production rate and types of oil to see their effects on the temperature profiles.

From these sensitivity studies, we identified the relative water production rates that create identifiable temperature anomalies in the temperature profile along a horizontal well. The results confirm the utility of temperature profiles in identifying water or gas entries if the well rate is large.
Fatigue Integrity Analysis of Rotating Coiled Tubing
Authors: Tipton S. M. , Carlson G. H. , Sorem J. R.
Published: December 2007

Conventional coiled tubing endures severe above-ground bending and straightening cycles that cause low-cycle fatigue to be the predominant factor limiting its useful life. For conventional coiled tubing, downhole bending events associated with wellpath curvature are negligible since the strains generated are orders of magnitude less severe than strains casued by above-ground cyclic bending, and are applied with a very low cycle count.

A new drilling rig is under development that rotates coiled tubing (CT) downhole, reportedly at rates on the order of 20 RPM, resulting in numerous operational benefits. However, rotation will impose additional rotating-bending events in the high-cycle regime as sections of CT pass through regions of high dog leg severity. This paper presents a study of the influence of downhole rotation on the fatigue durability of CT. In this study, fatigue data taken in the high and low cycle regimes from a variety of sources are used to assess the potential high-cycle fatigue damage that may be caused by downhole rotation. The results indicate that the damage is below the endurance limit and thus negligible relative to fatigue damage accumulated from above-ground bend-straighten cycles for conventional CT. This analysis also took into account another area of potential concern: circumferential abrasion that could occur when rotating coiled tubing contacts with the casing and/or wellbore. Surface roughness factors were estimated and used to modify life estimates. Results still indicate that sub-surface rotation-induced fatigue cycles should not detrimentally influence fatigue life relative to above surface fatigue cycles.

Experimental results are presented which validate the conservatism of the assumptions made for surface roughness factors. The results also demonstrate that the abrasion process causes compressive residual surface stresses that somewhat offset the detrimental effect of a rougher surface.
A Fully Implicit, Compositional, Parallel Simulator for IOR Processes in Fractured Reservoirs
Authors: Naimi-Tajdar R. , Han C. , Sepehrnoori K. , Arbogast T. J. , Miller M. A.
Published: December 2007

Naturally fractured reservoirs contain a significant amount of the world oil reserves. A number of these reservoirs contain several billion barrels of oil. Accurate and efficient reservoir simulation of naturally fractured reservoirs is one of the most important, challenging, and computationally intensive problems in reservoir engineering. Parallel reservoir simulators developed for naturally fractured reservoirs can effectively address the computational problem.

A new accurate parallel simulator for large-scale naturally fractured reservoirs, capable of modeling fluid flow in both rock matrix and fractures, has been developed. The simulator is a parallel, 3D, fully implicit, equation-of-state compositional model that solves very large, sparse linear systems arising from discretization of the governing partial differential equations. A generalized dual porosity model, the multiple-interacting-continua (MINC), has been implemented in this simulator. The matrix blocks are discretized into subgrids in both horizontal and vertical directions to offer a more accurate transient flow description in matrix blocks. We believe this implementation has led to a unique and powerful reservoir simulator that can be used by small and large oil producers to help them in the design and prediction of complex gas and waterflooding processes on their desktops or a cluster of computers. Some features of this simulator, such as modeling both gas and water processes and the ability of two-dimensional matrix subgridding to the best of our knowledge are not available in any commercial simulator. The code was developed on a cluster of processors, which has proven to be a very efficient and convenient resource for developing parallel programs.

The results were successfully verified against analytical solutions and commercial simulators (ECLIPSE and GEM). Excellent results were achieved for a variety of reservoir case studies. Applications of this model for several IOR processes (including gas and water injection) are demonstrated. Results using the simulator on a cluster of processors are also presented. Excellent speedups ratios were obtained.
Impact of Intelligent Wells on Oilfield Scale Management
Authors: Kavle V. , Elmsallati S. , Mackay E. , Davies D.
Published: December 2007

The main challenge facing the oil industry is to reduce development costs while accelerating recovery while maximising reserves. One of the key enabling technologies in this area is intelligent well completions. Downhole inflow control devices allow for the flexible operation of non-conventional wells. By placing sensors and control valves at the reservoir face, engineers can monitor reservoir and well performance in real time, analyse data, make decisions and modify the completion without physical intervention to optimise reservoir and asset performance. They provide the ability to independently control each valve individually from the surface to maximise oil production and/or minimise formation water and/or gas production. However, they may also be used to address other produced water management issues, such as inorganic scale control.

This paper describes the potential risks posed specifically to intelligent completions by scale deposition. The potential benefits to scale management that ICVs, such as control of scaling brine production and effective scale inhibitor placement, are described. Calculations are performed for a North Sea field with a barite scaling risk, and the cost benefit - specifically to scale management -of using ICVs is evaluated. These calculations demonstrate that intelligent completions significantly reduce the scale inhibitor chemical costs while improved scale inhibitor placement is achieved.
Advanced Collaborative Environments in BP
Authors: Edwards T. , Saunders M. , Moore-Cernoch K.
Published: December 2007

The Advanced Collaborative Environment (ACE) Programme is BP's strategic deployment vehicle for the global implementation of ‘Real Time’ Production and Drilling Operations Support Environments. ACE's are a key theme within BP's FIELD OF THE FUTURE technology leadership area.

This paper will describe current operational environments in Stavanger, Aberdeen, Houston and Baku and then move on describe future plans for multi-asset support environments to support Deep Water GOM assets, Caspian assets, North Sea operations. It will also highlight the opportunity for the fully collaborative office environments in a number of new office locations within BP.

BP believes that there are five key elements for success when implementing Advanced Collaborative Environments:

– People – Process – Technology – Physical Environment – Organisation

The integration of these five elements is the key to a successful ACE implementation.

The paper will conclude with a summary of some of the key business benefits attained from the application of ACE's with BP's drilling and production operations.
Observations on Characterization of Defects in Coiled Tubing From Magnetic-Flux-Leakage Data
Authors: McJunkin T. R. , Miller K. S. , Tolle C. R.
Published: December 2007

This paper presents observations on the sizing of automatically detected artificial flaws in coiled tubing samples using magnetic-flux-leakage data. Sixty-six artificial flaws of various shapes and types, ranging from 0.30 mm deep pits to slots with length of 9.5 mm, in 44.45 mm outer diameter pipe were analyzed. The detection algorithm and the information automatically extracted from the data are described. Observations on the capabilities and limitations for determining the size and shape of the flaws are discussed.
Challenges in Planning, Installation, and Operation of Coiled-Tubing Drilling Equipment on a North Sea Platform
Authors: Taggart M. , King J. A.
Published: December 2007

Coiled-tubing drilling (CTD) is a well-established, common application in some areas, particularly Western Canada. However this practice has not grown to similar activity levels in the North Sea. Two CTD projects have been carried out on UK North Sea platforms since 1999 and it is over 4 years since the most recent operation.

As a result of the sustained high oil price, North Sea operators are looking for methods of sidetracking existing wells to access isolated or stranded oil reserves. The condition of some North Sea drilling rigs is such that a significant financial investment is required if they are to return to conventional drilling. CTD is one option that enables operators to access these reserves, without the need to recommission the original drilling facility.

The extremely low activity levels of CTD in the UK has led to the challenge faced by service companies of supplying suitable equipment and experienced personnel, to safely and effectively manage and perform a CTD operation.

This paper discusses the challenges faced and some solutions developed for a recent CTD operation carried out on the Gannet ‘A’ platform, located in the Central North Sea.

In addition to the challenges mentioned above, to deliver a successful well, several new technologies and equipment were incorporated into the application of CTD to the Gannet field.
Reel-to-Injector Fluid-Flow Analysis Using CFD Software
Authors: Bailey M. B. , Blanco I. , Rosine R. S.
Published: December 2007

Until recently, fluid flow through coiled tubing (CT) was only discussed as a theory or an idea. With the aid of some sophisticated new software technology, Computational Fluid Dynamics (CFD), an understanding of the actual flow patterns of fluids in CT is now possible. This paper discusses a more complete study of multiple CT string components and their effect on fluid flow.

Analysis of individual components or systems has been performed, but combining systems can change the outcome of the results. Previous analysis simulated a straight section of tubing running through a tubing guide. This analysis assumed fully developed flow entering the straight section of tubing. Based on results of an industry consortium, the flow into the straight tubing coming off the reel may not be fully developed. To expand the study of the actual full-scale model of a CT string, in this study, additional portions of the string will be included. The fluid-flow phenomenon from the reel and its effect on the flow path in the straight section of the tubing between the reel and tubing guide will be incorporated into the model. The results could affect the centrifugal forces and flow-path patterns previously thought to affect erosion. Results generated from these studies could help in understanding erosion principles, including sand particle migration and movement.
Optimization of Coiled-Tubing Acidizing Through Real-Time Staged Fluid Tracking
Authors: Zheng A. S. , Bucher R. , Allcorn M.
Published: December 2007

In coiled tubing acidizing, a variety of fluids are pumped through coiled tubing in certain sequence to create the optimized downhole condition to treat the wellbore. Typically, prior to the coiled tubing reaching the target treatment zone, a neutral fluid may be pumped into coiled tubing during running-in-hole (RIH) for circulating purpose. Once at the targeted treatment zone, a pumping schedule (such as pre-flush, treating and post-flush fluids) may be used to treat the wells. During the operations, the coiled tubing operator may also move the coiled tubing (either running-in-hole or pulling-out-of-hole) while staged fluids are being pumped. It is desirable to track the movement of staged fluids inside coiled tubing to optimize the treatment. This paper presents a new technology to track the movement of stage fluids inside coiled tubing. It includes real time surface and downhole measurements, fluid and gas modelings and friction pressure drop calculation along coiled tubing. This new technology allows operators to optimize coiled tubing running speed and surface pumping to create the desired action downhole. The availability of staged fluids information downhole also opens the possibility for real time treatment evaluation. Several field job cases are reviewed to demonstrate the effectiveness of this new technology.
The Use of Finite-Element-Calculated MFL Signals To Study Characterization of Defects in Steel Coiled Tubing
Authors: Breidenthal C. , Larin G. E. , Tipton S. M. , Stanley R. K.
Published: December 2007

A primary consideration with coiled tubing (CT) is that it is consumed by fatigue loading during routine operations. Also, rugged oilfield conditions routinely lead to corrosion and other mechanical surface damage. Since fatigue is a surface phenomenon, the presence of a surface imperfection has a significant influence on fatigue damage mechanisms. This paper describes the study of magnetic flux leakage (MFL) inspection signals caused by surface defects in the form of milled circumferential grooves in steel CT. The focus of the investigation is to identify and estimate the size of surface defects based on characteristic MFL signal features. It is demonstrated that this effort is greatly enhanced by finite element analysis (FEA). The ultimate objective is to accurately extract surface flaw dimensions from conventional MFL signals. These dimensions are used in computer CT life prediction models.

An axisymmetric FEA model is developed and used to calculate leakage flux density solutions for milled circular and rectangular shaped grooves in 1.75" O.D. x 0.156" W.T., 90- ksi CT samples. FEA results are compared to axial and radial MFL signals measured with an experimental inspection unit. Favorable agreement is observed between experimental and FEA data. Furthermore, signal features are correlated with the known slot geometries to identify basic geometry recognition patterns for different circumferential grooves. Signal features reveal qualitative and quantitative trends relative to surface flaw dimensional characteristics.

The need persists to make the operator's string management decision-making process more reliable and automatic with respect to determining fatigue life expectancy. The obstacle here is that due to the inherent inaccuracies in commonly used MFL inspection techniques, there is limited reliable real-time flaw evaluation and characterization capability.
Coiled-Tubing-Deployed Extended-Length Patches Extend Wells’ Production in Prudhoe Bay, Alaska
Authors: Julian J. Y. , Cismoski D. A. , Smart J. C. , Wendt D. D.
Published: December 2007

A non-rig Coiled Tubing Unit (CTU)-deployed tubing patch technique was developed at Prudhoe Bay, Alaska, which provides an inexpensive remediation for wells with production tubing by "A" annulus communication. Extended-length patches (which consist of two retrievable hydraulically set packers spanned by jointed pipe) are a vast improvement over older technology that limited patch length to 35’. Patches of up to 5000’ of 3.5" OD jointed pipe can now be deployed, significantly increasing the viability of repairing a larger percentage of the wells shut in due to loss of tubing integrity.

Extended-length patches are deployed with a crane, a service CTU, and a wellwork platform. The wellwork platform provides adequate clearance for the existing wellhead and workover BOP stack, and protects against arctic conditions of -40 degrees F ambient and -80 degrees F wind chill. The advantages of this system over conventional rig workovers are that there is no need to pull tubing and it has faster mobility and ease of scheduling. Typically, extended- length patches are only 10-20% of the costs to replace tubing with a rig workover.

This paper outlines the results of this work and provides a systematic approach for design and deployment of an extended-length jointed patch. The technique has its greatest application where rig mobilization costs are high, such as offshore, remote, or arctic locations.
Real-Time Depth Measurement with Coiled Tubing Results in Successful Well Recompletion
Authors: Greenaway R. , Coston C.
Published: December 2007

In an environment of high drilling activity and a limited amount of rigs, available alternative completion methods using Wireline or coiled tubing enables a more efficient drilling and completion process. For a successful completion, depth control is critical for the placement of perforating guns and completion hardware. Common practice is to perform the perforating using Wireline, which becomes challenging with wellbore angles over 60 deg.

The use of coiled tubing enables the completion of highly deviated or horizontal wellbores, but depth critical operations performed using coiled tubing historically have presented industry challenges. Using the innovative real time depth measurement (RTDM) tool overcomes the limitations of other down hole depth- correlation methods.

This paper describes the design, planning and execution of a completion in a horizontal well using coiled tubing and a RTDM tool.
Field Trial of QT-16Cr Chrome Coiled Tubing Used as a Workstring on the North Slope, Alaska
Authors: Julian J. Y. , McLellan B. J. , McNerlin B. J. , Martin J. R. , Burke K. W. , Meaux C.
Published: December 2007

QT-16Cr chrome coiled tubing was introduced in 2003, but its use has been limited to velocity strings in corrosive environments. Questions concerning its feasibility as a workstring prompted field testing of a reel of QT-16Cr on the North Slope, Alaska.

Following preliminary laboratory testing, a QT-16Cr reel was deployed in the field and performed a variety of standard coil tubing applications on a daily basis for a three-month field trial. Observations and data were gathered during the field testing to determine operating guidelines, applicability, and limitations of this new coiled tubing technology. The successful field trial indicated QT-16Cr has increased low cycle fatigue life, superior abrasion resistance in chrome completions, and higher resistance to damage in corrosive environments in comparison to standard HS-80 coiled tubing.

This paper documents the testing and results of the lab and field studies. In addition, standard operating procedures for QT-16Cr are described and provide easily implemented guidelines which should work in virtually any area coiled tubing operations are performed. This paper is significant for worldwide coiled tubing operations, especially in areas with high rates of coiled tubing corrosion and where coiled tubing wear is significant due to abrasive tubing tubulars.
Production-System Optimization of Gas Fields Using Hybrid Fuzzy-Genetic Approach
Authors: Park H. -J. , Lim J. -S. , Roh J. , Kang J. M. , Min B. -H.
Published: December 2007

The design of production systems of gas fields has been a difficult task because of the nonlinear nature of optimization problem and the complex interactions between each operational parameter. Conventional methods, which usually are stated in precise mathematical forms, cannot include the uncertainties regarding vague or imprecise information in the objective and constraint functions.

This paper proposes a fuzzy nonlinear programming approach to accommodate these uncertainties and applies to a variety of optimization processes. Specifically, the fuzzy λ -formulation is combined with a hybrid co-evolutionary genetic algorithm for an optimal design of gas production systems. Both the multiple conflicting objective and constraint functions for production systems of gas field are formulated in a feasible fuzzy domain. Then, the genetic algorithm is used as a primary optimization scheme for solving optimum gas production rates of each well and pipeline segment diameters to minimize investment cost with given constraints in order to enhance ultimate recovery.

The synthetic optimization method can find a globally compromise solution and offer a new alternative with significant improvement over the existing conventional techniques. It has been successfully applied to a wide variety of operational problems including well rate allocation and optimal design of pipeline networks. The reliability of the proposed approach is validated by a synthetic practical example yielding more improved results, offering a powerful tool for cost savings in future planning and the optimization of gas production operations.
Tracer-Flow Simulation for Characterization of Naturally Fractured Reservoirs by Streamline Method
Authors: Iino A. , Arihara N. , Waseda U. , Okatsu K.
Published: December 2007

A simulation model for the tracer response analysis in naturally fractured reservoirs was developed by double-continua formulation. Waterflooding in dual-porosity dual-permeability reservoirs is first modeled by the streamline approach. Then flow of the water-soluble tracer described by the coupled convection-dispersion equations is combined. First, 1-dimensional convection-dispersion equation is solved along each streamline in the matrix and fracture systems by ignoring the gravity and transfer terms. The concentrations are mapped onto the grid, and corrected with gravity and transfer.

The model is capable of conducting tracer flow and waterflooding simulation in field-scale dual-porosity dual-permeability systems. It is developed particularly for analyzing multiple-well tracer tests in heterogeneous fractured reservoirs.

The model is validated for homogeneous and heterogeneous permeability distributions comparing with results from Eclipse. Effectiveness of the CFL condition and a TVD scheme to control stability and numerical dispersion are evaluated and analyzed. In the heterogeneous case, the saturation fronts and tracer responses from the model are less smeared than those from Eclipse. The model is also run for validation and sensitivity cases with different dispersivity.

Finally, tracer responses for a multiple injection/production scheme in a realistic reservoir including mega-fractures are simulated. Simulations demonstrate the potential of the streamline approach for characterizing heterogeneity of the fractured distribution, and for identifying flow paths.

Evaluation of heterogeneous fracture developments is critically important for assessing the reservoir performance, and yet remains to be a difficult issue. Tracer flow simulation by the streamline approach is particularly useful to interpret and model fracture-matrix systems in terms of flow properties and anisotropy. The streamline-based model is powerful for analyzing tracer response data with readily available visualization.
Maintaining the Stability of Deviated and Horizontal Wells: Effects of Mechanical, Chemical, and Thermal Phenomena on Well Designs
Authors: Zhang Jianguo , Yu Mengjiao , Al-Bazali T. M. , Ong Seehong , Chenevert M. E. , Sharma M. M. , Clark D. E.
Published: December 2007

Wellbore instability, particularly in shale formations, is regarded as a major challenge in drilling operations. Many factors, such as rock properties, in-situ stresses, chemical interactions between shale and drilling fluids, and thermal effects, should be considered in well trajectory designs and drilling fluid formulations in order to mitigate wellbore instability related problems.

A comprehensive study of wellbore stability in shale formations that takes into account the 3-dimensional earth stresses around the wellbore as well as chemical and thermal effects is presented in this work. The effects of borehole configuration (e.g. inclination and azimuth), rock properties (e.g. strength, Young's modulus, membrane efficiency and permeability), temperature, and drilling fluid properties (e.g. mud density and chemical concentrations) on wellbore stability in shale formations have been investigated.

Results from this study indicate that for low permeability shales, chemical interactions between the shale and water-based fluids play an important role. Not only is the activity of the water important but the diffusion of ions is also a significant factor for saline fluids. Cooling drilling fluids is found to be beneficial in preventing compressive failure. However, decreasing the mud temperature can be detrimental since it reduces the fracturing pressure of the formation, which can result in lost circulation problems. The magnitude of thermal effects depends on shale properties, earth stresses and wellbore orientation and deviation.

Conditions are identified when chemical and thermal effects play a significant role in determining the mud-weight-window when designing drilling programs for horizontal and deviated wells. The results presented in this paper will help in reducing the risks associated with wellbore instability and thereby lowering the overall non-productive times and drilling costs.
Streamline-Based Simulation To Investigate Interwell Connectivity and Tracer Transport in 3D Discrete Fractured Reservoir
Authors: Park C. , Kang J. M. , Jung Y. , Kim S.
Published: December 2007

Heterogeneity and complex intersection patterns make it difficult to characterize a fluid flow on fractured reservoir. Limited information and uncertainty of underground fractures can often produce unreliable results of an interwell connectivity and a tracer trajectory. Previous studies have not been able to analyze an interwell transport taking place in 3D discrete fracture networks since no method was developed for considering plate flow and channeling within the same fracture schemes. Also the conventional streamline simulation as the tool of solute transport, is incapable of extending to 3D discrete one due to meshing problem.

A new streamline simulator with direct quadrilateral mesh generator is developed to determine the interwell connectivity and the main flow path on random discrete fractured reservoir. Quadrilateral grids are generated on polygon-typed fractures by constructing boundary loops automatically. Mass is transported using streamline approach on the unstructured grids. Breakthrough curve has a positively skewed characteristic, which reveals that the solute transport is influenced by not only geological heterogeneity, but pressure distribution and variable apertures. A trajectory of streamlines and a distribution of residence time confirm that the tracer moves selectively along intersecting lines or fracture planes in the direction of decreasing pressure gradient. The new numerical approach using streamline method and automatic quadrilateral meshing algorithm makes the fast analysis of interwell connectivity in relatively realistic manner.
Production of Wet Natural Gas Containing Corrosive Components: Four Case Histories
Authors: Havlik W. , Thayer K. , Oberndorfer M.
Published: December 2007

In petroleum production, the problem of corrosive media attacking metallic structures is almost ubiquitous. Particularly severe environments are encountered in the production and transport of wet natural gas containing corrosive components, such as hydrogen sulphide and carbon dioxide. When exploring new gas fields, it is therefore a prerequisite to take into account the corrosivity of the respective fluids in all stages of the field development, in material selection, field layout, and facilities design. In preparation of the subsequent production phase, reliable corrosion monitoring programmes have to be selected, established, and implemented, as necessary. Furthermore the financial aspects always play an important role thus posing a real challenge for the engineer forced to seek a compromise between economics and design.

This paper gives a comprehensive overview of these considerations regarding four different OMV gas fields, two of them in Austria and two in Pakistan, which were successfully developed and brought on stream between 1967 and 2003. These fields do not only vary in their geographical position, but also in gas compositions, production start, and the location of gas dehydration units.

One major aspect dealt with in each of these cases, was material selection including metallic as well as non-metallic and composite materials. Where the initial decision was made in favour of carbon steel, different methods of corrosion protection, the application of corrosion inhibitors, corrosion monitoring, and intelligent pigging are discussed in the paper.

Comparing the various methods of resolution that have been worked out for all four case histories, experience gained in more than three decades of production and transportation of wet corrosive natural gas is presented.

Furthermore, results of the ongoing corrosion monitoring measurements in operation in the mature gas fields are discussed under the aspect of the remaining facility lifetimes.
Modeling of Stress-Dependent Hydraulic Fracturing in a Dynamic Flow Simulation
Authors: Kaselow A. , Ganzer L.
Published: December 2007

In this work we present a new approach to include the influence of hydraulically induced fractures on the performance of a reservoir. Hydraulic fracturing has become a state-or-the-art completion for all kinds of wells and reservoirs. Especially in the case of low permeable tight gas reservoirs, fracturing is essential for efficient reservoir exploitation. As a result of this, most gas wells are nowadays hydraulically stimulated. However, in the case of low permeable tight gas reservoirs with rather long fractures an appropriate simulation requires a highly-flexible time-dependent adaptive gridding of the model in the vicinity of the created fracture.

Our work is based on a recently proposed simulation method which combines a dual continuum approach with a time-dependent highly flexible gridding method in order to accurately simulate the influence of hydraulic fracturing on well and reservoir performance. We extend this method by treating the process of hydraulic fracturing as a part of the simulation. At any given time during the simulation a hydraulic fracture can be initiated for any desired well. The geometry of the fracture is inferred from a given state of stress, injection rate, and elastic rock properties using the Perkins-Kern-Nordgren model. Once the fracture is created the simulation grid is appropriately adopted.

We have implemented our approach in a commercial reservoir simulator which provides the necessary gridding flexibility and a dual continuum formulation that allows for the definition of locally restricted dual porosity or dual permeability cells. We will show how the accuracy and flexibility of our method enhances the ability to simulate the performance of a reservoir fracture treatment.
From Logs Scale to Reservoir Scale: Upscaling of the Petroelastic Model
Authors: Menezes C. , Gosselin O.
Published: December 2007

Any quantitative workflow, designed to constrain reservoir models to 3D/4D seismic data, must rely on petro-elastic modelling (or PEM), which relates fluid and rock properties to elastic ones.

Various scales must be accounted for: laboratory cores and well logs, geological and seismic grids, fluid flow simulator models. The petro-elastic model is generally a fine-scale model ("pem"), defined and calibrated for each specific case against core and logs data.

Aiming a 4D history matching workflow at the flow model scale, we then need to validate the use of the logs-scale calibrated "pem" at a larger scale, vertically and laterally. In this paper we proposed a methodology to define an upscaled "PEM" (new set of relationships valid at reservoir-scale), by tuning a fine-scale existing "pem", adjusting the most sensitive and relevant parameters, by an optimisation procedure.

Some previous studies already addressed downscaling problems (from reservoir to geological/seismic scale), but no previous work has proposed any solution for an upscaled PEM.

The main results of this study, using real field data, are the following:

■ upscaling is necessary, depending on the degree of static and dynamic heterogeneity; ■ the optimisation procedure is successful in calibrating a fine-scale "pem" to get a reservoir-scale "PEM"; ■ the procedure is sensitive to the Backus averaging parameters, which must be defined carefully; ■ this workflow is performed at wells in this study, but could be extended to reservoir scale, when a fine-scale geological model is available.
Live Well Deployment System
Authors: Evensen M. , Dagestad V.
Published: December 2007

Deployment of long tool strings is often critical for economical intervention in horizontal wells. This is because the extensive exposure to the reservoir produces a corresponding requirement for long perforation and straddle intervals.

A Norwegian operator has faced this challenge to increase recovery from horizontal offshore wells. Deployment of long tool strings into live wells can be a challenging task. When using the down-hole safety valve (DHSV) as the primary well barrier, the operator has only accepted snubbing as conveyance method. Deployment against DHSV on Coil Tubing (CT) and Wireline (WL) has not been accepted in live wells.
Integration of a Risk-Management Tool and an Analytical Simulator for Assisted Decision Making in IOR
Authors: Alvarado V. , Reich E. -M. , Yi Y. , Potsch K.
Published: December 2007

Risk management has become an integral part of the decision-making workflow in the oil and gas upstream business. As many oil fields reach a mature state, the need for rejuvenation and decline mitigation of assets set ground for Improved-Oil Recovery (IOR) opportunities. However, the associated decision-making process requires incorporating screening, reservoir simulation and financial evaluation, demanding complex multidisciplinary team efforts. It is important that any stage of the analysis, technical, strategic and economically sound decisions should be made.

On one hand, IOR screening, whether based on technical grounds or ‘gut feeling’ experience, or better yet on both criteria, leaves a number of possible IOR processes available for evaluation through simulation. Analytical simulation and applicability screening tools are often favored on early stages. However, their crude application could mislead the decision process if results are not carefully interpreted and combined with reservoir engineering expertise and additional evaluation criteria.

We propose to combine IOR screening strategies with spatial reservoir information to help to create appropriate sector models as starting point for more detailed evaluations. For this purpose, we couple an analytical simulator/IOR screening tool with a software tool that aids framing the IOR decision-making problem effectively, in the form of influence diagrams. From these diagrams, it is possible to create Tornado Diagrams, Decision Trees and Monte Carlo profiles that assist Reservoir Engineers with the task of properly and rationally framing the decision process, for example with regard to economic risk assessment and NPV analysis associated with IOR.

The coupling between both software solutions is proposed in a way that avoids the inflexible monolithic constructions. We illustrate advantages of the proposed approach through a speedy analysis of a publicly available case.
New Work Processes and Operation Forms: Efficient Data Utilisation and Online Collaboration
Authors: Millette P.
Published: December 2007

Although producing oil is a complex activity, the support of the total operation of any producing asset is hampered by several factors – remote locations, limited data access, low bandwidth data connections, distributed specialists and fragmented support teams. At the same time pressures of less personnel in-situ at the production and support centres is increasingly evident.

Challenges also exist of trying to ensure the optimisation of Production and operate with zero accidents, safety compliance, additionally in a ever-changing world we face increasing environmental monitoring and compliance regulations

Increasingly industry is turning to the people factors to try and assist the Oil & Gas Industry achieve the above objectives. Industry shows that people factors account for 35%-45% of abnormal situations in the process industry however the team resolving these situations are effectively individuals working on a common problem, rather than a team working together. Predominantly, this is because the team cannot see the same thing or look at issues together in real-time.
Building Human Capital to Meet the Demands in Well Intervention
Authors: Allcorn M. , Zemlak W. M. , Van Der Tuin R. G. , Stephens R. K.
Published: December 2007

The pace of activity, maturing profiles, incoming workforce expectations, and increasingly focused requirements on the industry’s well intervention needs, is demanding a new approach to building human capital. Today’s challenge is to build the required expertise in a fraction of the time previously available. This paper will provide an overview of current and future skill requirements to determine the most effective way to develop those skills, and a review of on-going programs to develop the required skill levels. Additionally, a review will be completed on the current learning tools as well as the integration of those tools in a comprehensive and accelerated development program.
Injection Tests as a Reliable Alternative to Conventional Well Testing: A Real Field Experience
Authors: Beretta E. , Tiani A. , Presti G. Lo , Verga F.
Published: December 2007

Environmental constraints and high costs, especially offshore, are making conventional well testing less and less feasible and accepted by the public Administration.

New options were thoroughly evaluated to find a viable alternative to standard production tests for characterizing the well productivity without surface production. An accurate investigation demonstrated that injection tests could provide all the information needed to calculate the well productivity at reasonably low costs and with a good degree of reliability.

Based on the results of laboratory and field pilot tests it was proved that injectivity tests could be successfully applied in a real sour oil field. Laboratory tests proved that brine could be a suitable injection fluid because there were no compatibility problems with the oil and the reservoir rock. It was verified that the interpretation of the pressure transients should be referred to the fall-off period rather than to the injection phase. The formation permeability thickness product (kh) could be correctly identified from the pressure derivative analysis only if multiphase-flow was assumed. The total skin value could also be obtained from the test interpretation.

The total skin comprises two components, a mechanical component due to permeability damage, and a bi-phase component due to fluid interaction in the reservoir. The biphase skin could only be evaluated with numerical well testing, provided that the fluid relative permeability curves were available. It was also demonstrated that the bi-phase component mainly depends on the injection rate, but is independent from the formation permeability.

Then, the well-known transient equation was applied to determine the well productivity index (PI) based on the kh and the mechanical skin. PI values calculated from injection tests compared satisfactorily with PI values measured from 6 DST tests performed on appraisal wells.
Novel Fluid Design Can Eliminate OBM-Cuttings Waste
Authors: Young S. , Rabke S.
Published: December 2007

With an ever increasing pressure on drilling performance and economics, the use of invert emulsion fluids has continued to be a necessity. Increased environmental responsibility has brought with it an increase in the cost and liability associated with responsible disposal of contaminated drill cuttings. In environmentally sensitive areas, it is unlikely that any discharges of contaminated cuttings will be permitted. Subsurface injection cannot be used as a solution in all cases, so other treatment methods must be found to minimize future environmental liability.

Developing invert emulsion drilling fluids designed to meet the demands of high-performance drilling and have chemical characteristics that can be used to optimize contaminated cuttings treatment has been key in minimizing environmental impact. Developing efficient treatment techniques tailored to the local environment has been equally important. The environmental responsibility picture has been completed by combining the chemistry and treatments to produce an end product that can be beneficially re-used in the local environment.

The authors will discuss the design changes in drilling fluid chemistry and show the field performance of these fluids. The associated treatment techniques that can be applied will also be reviewed, along with the local environmental climate required to ensure successful application of such treatments. The authors also will review the potential for beneficial reuse of contaminated cuttings in this context and show field trial results.
Facies Connectivity Modelling: Analysis and Field Study
Authors: Nurafza P. R. , King P. R. , Masihi M.
Published: December 2007

A statistical approach is proposed and validated against a realistic field dataset to model connectivity of low to intermediate net-to-gross reservoirs. An object based technique is used to model the spatial distribution of aligned isotropic and anisotropic bodies. The connectivity of the model is estimated using percolation theory. First account is made to evaluate the effect of the aspect ratio of the facies. The outcome is two universal curves for the connectivity and its associated uncertainty which can be used to estimate the connectivity of all sorts of body sizes and aspect ratios very quickly.

The approach is then reviewed for variable body sizes as well as a system with oriented bodies. An effective size based on the square root of the average area of bodies can be used to represent the distribution of body sizes. For systems with oriented bodies, a new aspect ratio is defined and the reduced percolation thresholds of the system are determined. The results show that with above changes the universal curves are still applicable for both orientated and variable size systems.

Finally, a conventional facies modelling of a carbonate layered reservoir is used to be compared with the results of the proposed method. The comparisons were in good agreement. It is found that the new method gave reliable and broad estimate of connectivity of the system in comparison with exact and uncertain results from modelling of real data, while the first one is so fast, the latter is so costly and time consuming. This framework can be further extended to evaluate recovery factor and sweep efficiency of a reservoir. The technique can also be used for preliminary evaluation of a reservoir as a quick method which offers fast estimates of important parameters of a reservoir based on its simple basic data.
Magnetic Resonance While Drilling—A Quantum Leap in Everyday Petrophysics
Authors: Bittner R. , Komarek F. , Thern H. F. , Kruspe T. , Kirkwood A. , Chemali R.
Published: December 2007

Magnetic resonance (MR) logging was originally intended for measuring fluid filled porosity, and for differentiating between producible and non producible fluids. Early tools however came with special operational requirements. Wireline logs were slow and sensitive to wash-outs; early logging while drilling (LWD) measurements did not tolerate tool vibrations. Both required a good deal of preplanning to accommodate limited capability hardware. The paper shows how problems of the past could be solved by the innovative technology of Magnetic Resonance Logging While Drilling (MR-LWD).

By returning to basics a new LWD magnetic resonance tool tolerant to vibration and easy to apply could be designed. The novel device acquires valuable data which can be used as well for formation evaluation as for geo-steering under normal drilling conditions and with standard operating practices. This was made possible by a short inter-echo spacing, by a special stabilization, and by a low magnetic field gradient. The new sensor operates with a minimum of preplanning and requires little to no interference with the drilling process.

We present an application of the new system in a European onshore well. In the case described we show how reliable deliverables such as porosity and pore-size distribution can be determined from MR-LWD. Formation boundaries and fluid contact can easily be determined. The clear logs and the intuitive presentation of data makes MR while drilling ready for everyday petrophysics.