bluuebunny/crossref_metadata_2025 huggingface dataset:
Comparisons of Reservoir Knowledge, Drilling Benefits, and Economic Advantages for Underbalanced and Managed-Pressure Drilling
Authors: Finley Doug , Ansah Joe , Gil Isabel , Lovorn Randy , Shayegi Sara
Published: December 2007

Underbalanced drilling (UBD) and managed pressure drilling (MPD) are gaining in popularity as drilling methodologies to overcome some of the problems faced in conventional overbalanced drilling. These techniques are complimentary technologies rather than completely separate techniques, MPD techniques at one time having been classified under UBD. Therefore, with the current terminology and the many similarities they are often confused with one another. Underbalanced drilling is a tool both for reservoir performance improvement and reservoir characterization as well as for addressing drilling problems. MPD, on the other hand, is primarily a solution for mitigating drilling related problems. Both result in a reduction of non-productive time (NPT). Sometimes a combination of both techniques may be required for the same well.

Different operators have chosen UBD and MPD with the goal of curtailing severe fluid losses and other drilling-related problems associated with conventional overbalanced drilling. Often times, while applying this technique to solve these drilling problems, the reservoir benefits have become apparent and have convinced the operators to go to full underbalance to realize the full reservoir production benefits without any period of overbalance throughout drilling, tripping, and completion operations. They have often found that when using UBD for reservoir production improvement, it is possible to perform comprehensive characterization of the reservoir while drilling. In some cases, zones that were not seen as productive during overbalanced operations have come to light, and reservoir characterization has enabled appraisal of these formations. Reservoir information obtained during the drilling phase can significantly reduce the time and cost associated with gathering and analyzing "well test" type data post-completion with conventional methods and these methods have been field tested and results compared to conventional well testing with favorable results.
Nonintrusive Pipeline-Inspection Techniques for Accurate Measurement of Hydrates and Waxes Within Operational Pipelines
Authors: Benson Dan , Robins Lee
Published: December 2007

This paper will describe the use of externally mounted, non-intrusive on-line diagnostic techniques for pipeline inspection that can be used to accurately measure the amount, location, and profile of any type of deposits within any pipeline. Therefore allowing timely intervention to take place reducing costs, allowing optimization of chemical treatments thus increasing environmental compliance and ensuring greater availability of the pipeline.

Three methods will be described:

Gamma-ray transmission scanning for accurate point measurements. Tomography measurements for detailed density mapping of pipeline contents. Radioisotope tracer injections to determine deposit profiles and inventory over long distances.

The gamma-ray transmission technique uses a small sealed source and a sensitive radiation detector positioned on adjacent sides of the pipe. The measured radiation intensity is directly related to the amount of deposit in the pipeline.

The Tomography scanning technique is an advanced method of gamma ray scanning. Multiple scans around a pipelines circumference using a single point source and a phased array of sensitive radiation detectors enables a very detailed density map of pipeline contents to be produced.

The tracer injection technique requires the injection of a small sharp pulse of low activity radioactive tracer into the line, enabling the fluid velocity between externally mounted radiation detector data loggers to be measured to better than 0.1% accuracy. Comparing this to the pipeline flow rate for the duration of the tests enables the amounts of deposit between successive detectors to be calculated.

The paper will give details of research work and results of several recent pipeline inspection projects.
Highly Successful Batch Application of Surfactant in North Sea Gas Wells
Authors: Schinagl Werner , Green Steve R. , Hodds Alan C. , Caskie Mark , Docherty Martin
Published: December 2007

Liquid loading in gas wells is a phenomenon that increasingly limits production in mature gas wells where reservoir pressures are insufficient to lift liquids out of wellbores.

Various technologies to artificially lift liquid associated with gas production exist, however in offshore fields most of them are not applicable for well completion or legal requirements. In the past soap sticks have been tried to foam up liquids, however these may never have reached the area where liquid had accumulated due to wellbore deviation. It was therefore decided to try liquid batch injection in several North Sea gas wells. The paper speaks about candidate selection, chemical screening, laboratory testing, operational considerations and the results of the offshore field trials.

The results from the first trials were above expectations. One cycling well was able to be kept online five times longer than under normal operating circumstances, while for another well, its time online more than doubled.

These results were the trigger for the next two sets of surfactant trials in the southern North Sea region, which were again successful.

In one well a downhole gauge was utilised to monitor the dramatic change in well behaviour, which gave great insight into the way the surfactant acted. This is discussed in detail in the paper. No foam-related problems were encountered at the platform as defoamer was injected at surface.

From these successful North Sea surfactant batch trials, it can be concluded that de-liquifying gas wells with the aid of surfactants can be a very effective and cheap way to increase gas production, mainly by keeping wells online for an extended period of time. Resolving the issue of liquid loading in maturing gas fields across the North Sea will lead to higher production rates (up to 30% from cycling wells) and an increase in reserves recovery.
Cliff Head Intelligent Completion With Coiled Tubing Deployed ESP—Increased Production, Reduced Life-cycle Cost
Authors: Way Chris , Daniel Simon , Bird Elsbeth , Jordan Jason , Guatelli Victor J. , Bettridge Justin M.
Published: December 2007

The Cliff Head well design includes multiple, innovative, new technologies in perforating, artificial lift and completion systems. The field development completion solution for this waxy crude includes CT (Coiled Tubing) deployed ESPs (Electric Submersible Pumps) combined with intelligent completion technology including permanent monitoring, multi-zone flow control and zonal isolation capability. The use of CT deployed ESPs potentially provides significant field life-cycle cost reductions by eliminating the need for drilling rig intervention to conduct ESP workovers. The zonal selectivity capability has resulted in demonstrable production enhancements in multiple wells within the early months of production.

This paper reviews the completion design applied to the Cliff Head development, which features multi-zone flow control utilising hydraulic, remotely controlled sleeves and down-hole lubricator valves with multiple packers. The ESP system provides down-hole pressure and temperature monitoring. These features, combined with flowrate, watercut, temperature and pressure monitoring at surface for each well, makes the design a truly complete intelligent solution. The paper continues to present a case study of the deployment operations, including simultaneous completion operations on the drilling rig and CT ESP deployment on the platform.
Improving Organisational Performance Through Our People—Cross-Industry Experiences Shared
Authors: Wiltshire Kevin
Published: December 2007

Across many industries, frequently organisational performance improvement does not extend beyond enhancements to equipment and production processes.

There has been a renaissance in respect to the realisation of the importance of our people resource, and the way in which our management and development of our teams links to staff retention and increased performance.

This has been particularly prevalent within the automotive as well as other, diverse industries. Our work with the automotive industry, and companies from sectors such as telecommunications, construction, transport, nuclear and financial services, has given us the opportunity to identify ‘best-practice’ in this area.

This paper explores the relevance of cross-industry findings, and relates this to the challenges faced within the offshore arena.

Our experience in this people development area, and the source data on which our paper is based, comes from our work in relation to:

Cultural integration across multi-national organisations

Management of team performance

Alignment of staff objectives with company strategic direction

Staff retention through management styles & motivational techniques

Selection and assessment activities for effective staff recruitment.

This paper brings to the table a perspective from outside of the offshore industry, and provides an insight into the challenges being faced in other industries, relevant to those within the offshore industry. It provides a confirmation that this industry is not alone in the challenges it faces.
Reservoir Candidate Screening: The SURE Way to Successful Under-balanced Drilling Projects in ADCO
Authors: Keshka Ashraf , Rawahi Ali Salem Al , Murawwi Rashed Abdulla Al , Yaaqeeb Khalid Al , Qutob Hani , Boutalbi Said , Villatoro Jaime
Published: December 2007

Abu Dhabi National Oil Company (ADNOC) and its group of companies are considering adapting new technologies to ensure that strategic resources are optimally explored, developed and produced during the life cycle of their oil and gas fields. Underbalanced Drilling (UBD) technology, which can achieve these objectives effectively when applied in conjunction with horizontal drilling techniques, is being considered among various options.

Abu Dhabi Company for Onshore Oil Operations-ADCO, decided to pioneer the introduction of the new technology. A systematic scientific approach was applied to screen thirty reservoirs for underbalanced drilling candidacy, in order to identify the best potential candidates from a given portfolio and to ensure a successful pilot application.

The screening process incorporated reservoir, drilling, and operational data with risk analysis into a rigorous expert system aimed at maximizing the value of any UBD operation. The screening process was performed in two phases;

Phase I comprised of: Evaluating and ranking thirty reservoirs with respect to their risked probability of being successfully exploited with horizontal underbalanced drilling and completion techniques as opposed to conventional drilling and completion techniques.Comparing candidate reservoirs against global database of analogues proven to be suitable with UBD.Selecting the best three candidates for the Phase II detailed reservoir damage analysis and productivity forecast.

Phase II comprised of: Identifying the formation damage mechanisms that are expected to occur in each of the three reservoirs.Comparing underbalanced and overbalanced costs, production rates, projected revenues and net present value.Ranking the three candidates for UBD application.

The paper describes the expert system methodology used in the screening process and the results obtained. The detailed economic analysis presented in Phase II of the study would help ADCO determine the benefit that underbalanced drilling could provide compared to competing conventional drilling & completion technologies.
Dual Subsea Choke Applications for High-Pressure Reservoir Development
Authors: Meng Weihong , Prescott Neal
Published: December 2007

As the petroleum reserve discovery goes deeper in the offshore oil industry, high pressure reserves are discovered. Those wells will produce at very high initial flowing wellhead pressures (> 10,000 psi) and at much lower flowing wellhead pressures after a period of production. This presents a significant challenge for design and operation of the production system, especially, the subsea production choke, being required to have very low flow coefficient (Cv) in early life to restrict flow, and very high Cv in late life to reduce pressure loss. Initially, the pressure across the choke is required to be 5000 psi or higher. Associated with the high pressure loss across the choke, the Joule-Thompson effect will cause much higher temperatures (up to 30-40 °F) at the downstream of the subsea choke compared to non-restricted flow. The elevated temperature challenges the materials of the downstream equipment and the pipelines/risers.

This paper presents an innovative concept — using dual subsea chokes to split the pressure to protect the chokes and improve production operations. The advantages and disadvantages of using dual subsea chokes are presented.
People and Sustainable Development
Authors: Colmer Roger
Published: December 2007

Intellectually all those associated with the Exploration and Production business can articulate the critical role that people play in an industry which is risk based and capital intensive. With demographic pressures and fewer students pursuing science and technology in the developed world the criticality of attracting, developing and retaining people is paramount. In the developing world there is often an ample supply of graduates however the challenge of building real capability and experience cannot be underestimated.

Against the background of the global challenges it is proposed that people be viewed much more as a part of sustainable development. The classic sustainable development model, comprising of economics, the environment and the community has people at every level. To achieve the goal of a long term sustainable contribution from the people currently in the industry and those considering joining will take a major shift from some of the development models currently employed.

This paper examines the significance of a competent trained and motivated workforce against the background of the SD principles. The themes developed are based on extensive contact and discussions with both National and International oil and gas companies around the globe. Getenergy as an independent broker of training and development (learning) has gathered a fascinating insight to the challenges, and some of the possible solutions. The concept of building on the model of sustainable development has been raised and tested at many forums around the world and it is felt that bringing it to OE2007 will enhance the debate and help drive the concept forward.
Development of Artificial Neural Networks To Predict Differential Pipe Sticking in Iranian Offshore Oil Fields
Authors: Miri R. , Sampaio J. , Afshar M. , Lourenco A.
Published: December 2007

Differential sticking is known to be influenced by drilling fluid properties and other parameters, such as the characteristics of rock formations. In the past, multivariate statistical analysis techniques and simulated sticking testes using different drilling fluids have been performed to identify and modify parameters that lead to differential pipe sticking in order to minimize or prevent sticking. Recently, an application of neural network methodology to predict differential pipe sticking incidents in Gulf of Mexico has been published by Halliburton1. This paper presents two different types of artificial neural network that can provide solutions for problems associated with differential pipe sticking.

A stuck pipe database was developed with data from 64 side tracked and horizontal wells drilled in reservoir section using oil based and synthetic drilling fluid from different fields in the Persian Gulf. Two three-layers feed forward networks; Multi Layer Perceptron (MLP) and Radial Basis Functions (RBF) with back propagation training algorithm were used to develop stuck pipe predictive models for oil base and synthetic drilling fluid together. Using these models, prediction of the probability of stuck pipe may be undertaken to monitor drilling operations for stuck pipe avoidance. A sensitivity analysis was also done by applying data of different fields separately to identify the parameters that had more effect on tendency to differential pipe sticking. The proposed methodology can be used for optimum drilling fluid design during well development in Persian Gulf, Offshore Iran.
Aberdeen Foyer—Platform to Work
Authors: Mateo Ann , Harris Edel
Published: December 2007

Background

Aberdeen Foyer is a successful charitable organisation working to prevent and alleviate youth homelessness and unemployment in Aberdeen and Aberdeenshire.

Established in 1995, our organisation:

is a creative and dynamic organisation that works with individuals, staff and partners to seek out new opportunities and embrace new challenges tackles exclusion and promotes equality by helping people equip themselves with the experience and skills needed to realise their potential gives young people in crisis the opportunity to tackle their homelessness and it's causes whilst working towards a more stable and positive future

Aberdeen Foyer's success is built on its ability to deliver innovative, cost-effective solutions and in forging dynamic partnerships with private sector companies, key statutory agencies and other voluntary sector bodies.
CO2 Storage Geomechanics for Performance and Risk Management
Authors: Bérard T. , Jammes L. , Lecampion B. , Vivalda C. , Desroches J.
Published: December 2007

Controlling the trapping of CO2 in the subsurface, i.e. storage containment, is of fundamental importance for a safe geological storage of carbon dioxide. During CO2 injection, increasing fluid pressure, temperature variations, and chemical reactions between fluids and rocks inherently affect the state of stress inside the reservoir and in its surroundings. Besides, the mechanical properties of the rocks exposed to CO2 may be altered. The impact of the resulting deformations on seal integrity must therefore be assessed in order to properly manage containment performance and leakage-incurred risks.

The analysis starts with the construction and the calibration of a Mechanical Earth Model of the site, through joint analysis of geologic, seismic, logging, drilling, and laboratory test data. Such a model consistently describes ambient stresses, fluid pressures, and poro-mechanical and strength properties of the formations. It is linked to a reservoir model to achieve initial equilibrium and also to further simulate the coupled transport, chemical and mechanical processes occurring during CO2 injection operations and the subsequent re-equilibration. The predicted stress path allows the evaluation of the mechanical stability of both cap-rock and faults (which may bound the reservoir, penetrate the cap-rock or intercept wells). The stability of wells in formations experiencing strain is also investigated.

In addition, an accurate Mechanical Earth Model contributes to optimizing well construction and stimulation operations. Profiles of stresses and mechanical properties along a planned-well trajectory allow designing a drilling operation that will maximize subsequent hydraulic isolation of the well by optimizing the wellbore condition. Similar information along existing wells helps to control hydro-fracture propagation when injectivity enhancement is required.

The Mechanical Earth Model can be used to develop operating envelopes for well placement, hydraulic fracturing, and CO2 injection that best ensure containment while achieving injectivity and capacity requirements.
Building Complex Structural Frameworks
Authors: Hoffman K. S. , Neave J. W. , Nilsen E. H.
Published: December 2007

The technical and economic challenges of exploring and producing in deepwater environments require that risk and uncertainty be reduced as much as possible. One of the major contributors to uncertainty – and therefore risk – is creating a sound structural framework. Sophisticated geostatistical techniques are commonly used to create facies and petrophysical models which are used for analyzing uncertainty and making reservoir management decisions, but the underlying structural frameworks often do not correctly portray the true structure. Current methodologies have limitations to the types of fault intersections, the number of faults that realistically can be modeled, and/or the type of grid that can be generated from the reservoir model.

The structural framework is often a compromise between the actual structure and what the modeling system allows, particularly in areas with large numbers of Y-intersections, low angle faults, or reverse faults. We have developed a new technique for structural framework building that takes a unique approach to constructing the initial fault model, where fault relationships and intersections are easily defined and controlled.

This technique does not have limitations to the types of fault intersections nor to the number of faults which may be included in a reservoir model, and provides the tools to build a reservoir grid using these complex fault intersections. When the structural framework more accurately represents the interpretation, subsequent calculations such as reserve estimates, analysis of structural uncertainty, or well placement can be made with more confidence.

The simplicity of building and editing the fault relationships, creating the stratigraphic model, and building the reservoir grid means that an asset team can easily update a model, test different interpretations, and use the model for both geologic and engineering applications.
New Downhole Fluid Analyzer Tool for Improved Reservoir Characterization
Authors: Dong C. , O'Keefe M. , Elshahawi H. , Hashem M. , Williams S. , Stensland D. , Hegeman P. , Vasques R. , Terabayashi T. , Mullins O. , Donzier E.
Published: December 2007

Downhole fluid analysis (DFA) has emerged as a key technique for characterizing the distribution of reservoir fluid properties and determining zonal connectivity across the reservoir. Information from profiling the reservoir fluids enables sealing barriers to be proven and compositional grading to be quantified; this information cannot be obtained from conventional wireline logs. The DFA technique has been based largely on optical spectroscopy, which can provide estimates of filtrate contamination, gas/oil ratio (GOR), pH of formation water, and a hydrocarbon composition in four groups: methane (C1), ethane to pentane (C2-5), hexane and heavier hydrocarbons (C6+), and carbon dioxide (CO2). For single-phase assurance it is possible to detect gas liberation (bubble point) or liquid dropout (dew point) while pumping reservoir fluid to the wellbore, before filling a sample bottle.

In this paper, a new DFA tool is introduced which greatly increases the accuracy of these measurements. The tool uses a grating spectrometer in combination with a filter-array spectrometer. The range of compositional information is extended from four groups to five groups: methane (C1), ethane (C2), propane to pentane (C3-5), C6+, and CO2. These spectrometers, together with improved compositional algorithms, now make possible a quantitative analysis of reservoir fluid with much greater accuracy and repeatability. This accuracy enables comparison of fluid properties between wells for the first time, thus extending the application of fluid profiling from a single well to multi-well. Field-based fluid characterization is now possible.

In addition a new measurement is introduced — in-situ density of reservoir fluid. Measuring this property downhole at reservoir conditions of pressure and temperature provides important advantages over surface measurements. The density sensor is combined in a package that includes the optical spectrometers, fluid resistivity, pressure, temperature, and fluorescence measurements that all play a vital role in determining the exact nature of the reservoir fluid.

Extensive tests at a pressure/volume/temperature (PVT) laboratory are presented to illustrate sensor response in a large number of live fluid samples. These tests of known fluid compositions were conducted under pressurized and heated conditions to emulate reservoir conditions. In addition several field examples are presented to illustrate applicability in different environments.
Integrating Quantitative and Qualitative Reservoir Data in Sand Prediction Studies: The Combination of Numerical and Geological Analysis
Authors: Webster Craig M. , Taylor Philip G.
Published: December 2007

The methodology for predicting sand production is in general constant across the industry. That is the determination of formation strength and field stresses and the application of them to a failure model. However, the variety of models available and their applicability and accuracy can be confusing with the results not always representing what is experienced under production conditions.

This paper introduces a more holistic approach to sand production prediction which not only utilises numerical analysis, but also includes a qualitative approach using geological information. With respect to the numerical analysis the determination of various parameters used in modelling sand production and their effectiveness for different reservoir and production conditions is discussed. An overview of the various tests considered useful in calibrating these parameters is also presented. The geological approach discusses the impact of mineralogical, depositional, structural and diagenetic factors which can impact on the propensity for sand, but which are not fully taken into account by a purely numerical approach.

The advantages and disadvantages of each of these aspects are presented and synergies identified between numerical and qualitative analysis. Case histories are presented which show that each of these methodologies, when used independently, can present dissimilar results. This may ultimately lead to recommendations which can result in costly operations and unnecessary equipment deployment. However, when numerical modelling and geological methods are used in conjunction with one another, the results present a more realistic and practical view of the formation sands and their potential for solids production during the life of the well.
Understanding Reported Skills Shortages in Geophysics, Subsurface, and Subsea— A Case Study Example of the Developing Paradigm within the Oil and Gas Industry of Using a Dynamic and Holistic Model to Address the Issues Affecting the Ability to Build and Sustain its Workforce Talent Pool
Authors: Thomas A.
Published: December 2007

Oil and gas operators and their suppliers reported skills shortages in the key occupations of geologists, geophysicists and subsurface/reservoir engineering. Subsea UK also reported deficiencies for highly qualified and experienced engineers.

The lead time to "produce" an appropriate individual (right technical degree, additional expertise etc) for the operator and subsea sectors requires long term planning based on sound information and intelligence.

The objectives of the research were to:

Understand the key factors, which contribute to identified problems of the availability of people to carry out jobs/roles in geology, geophysics and subsea engineering. Evaluate the current provision within the learning supply chain; capacity; capability and current action. Assimilate information from employers and learning providers such that recommendations can be made to improve agreed issues and challenges.

Summary of the Findings

Companies reported that the problem was less to do with new graduates, in many cases small numbers of first-degree qualified graduates are recruited, and more about:

The difficultly in finding people with 5 years plus experience and filling senior positions. The need for graduates with "critical thinking" and "problem quantification and defining skills" as well as excellent technical knowledge. Super Majors and large contractors undertaking global recruitment, which mitigates their dependence on UK graduates but has repercussions for university departments. Smaller companies experience problems recruiting for UKCS at all levels. Specific issues facing subsea.

Recommendations

For Upstream Oil and Gas to sustain its core areas of exploration and production will require an agreed and sustainable plan.

The issues which can be directly affected by the industry, can be grouped into:
Plugging of Fractures in Chalk Reservoirs by Enzymatic Induced Calcium Carbonate Precipitation
Authors: Larsen Jan , Poulsen Mikael , Lundgaard Thomas , Agerbæk Mikkel
Published: December 2007

Natural or induced fractures in a chalk reservoir can significantly reduce the recovery from a field. Therefore, plugging of fractures with a wide range of materials has been investigated over the years. Calcium carbonate, being the main constituent of the reservoir itself, is an obvious candidate. In order to apply calcium carbonate as a plugging fluid, a mechanism for delaying the precipitation has previously been suggested in the literature. This mechanism involves enzymatically induced plugging based on the mechanism of the enzyme urease converting urea into ammonia and carbonate. When carbonate is formed, it will precipitate with calcium in solution forming calcium carbonate. However, the amount of produced calcium carbonate was relatively low and the costs of the used stabilizer and high purity enzyme source was prohibitively high for bulk use. Furthermore, the calcium carbonate was produced as a slurry of small particles, which is deemed less efficient for fracture plugging compared to larger crystals or aggregates.

In this paper work on design of an improved plugging fluid based on enzymatic calcium carbonate precipitation and optimization towards a field applicable solution is presented. The relatively expensive stabilizer and enzyme source is replaced with a low cost ingredient, which also improves the rate of precipitation. By optimizing the concentrations of the reactants, we have improved the yield of calcium carbonate from the initial 20 g/L to more than 200 g/L. Furthermore, we have been able to control the crystallization and obtain much larger calcium carbonate crystals. Laboratory plugging experiments have shown that larger crystal sizes significantly improves the durability of the formed plugs.
Practical Uses of Swellable Packer Technology To Reduce Water Cut: Case Studies From the Middle East and Other Areas
Authors: Keshka Ashraf , Elbarbay Abdalla , Menasria Cherif , Smith Pete
Published: December 2007

Horizontal wells have become very common in the Middle East because of their capability to increase reservoir contact, particularly in carbonate reservoirs. These types of formations often are naturally fractured, and because of channeling from underlying aquifers, allow the ingress of water into the production process systems. When water breaks through to the well completion, it tends to increase and becomes preferentially produced, thereby reducing the volume of produced hydrocarbons. This phenomenon adds cost to the well operation because of the requirement to lift, separate, treat and dispose of the water. Preventing and managing water-cut through cementing, chemical application or the use of mechanical openhole barriers such as inflatable packers is costly, and often, the method chosen is not effective.

This paper will discuss the use of swellable packers to provide a long-term, completely effective, water shutoff tool. These packers use expanding rubber around the packer that expands to seal the annulus. When expanded, a permanent seal is created, regardless of whether the packer has been run as a straddle or as a plug. The packers can be used in open and cased-hole applications in all the most common oil-and gas-well environments.

This paper discusses the development and design of the packer and presents case histories from the Middle East and other parts of the world that illustrate the advantages that swellable packer technology can provide to operators in reservoirs in which water break-through has been predicted or experienced.

In these case histories, it will be shown that the packers significantly reduced water cut, which in turn, reduced water disposal costs and intervention needs while increasing production rates and extending field life.
Simulation Study of Waterflooding Performance Using Horizontal Wells in Heterogeneous Reservoirs, HMD Field Algeria
Authors: Hamadouche A. , Tiab D.
Published: December 2007

Due to the improvement in horizontal well construction technology, there is a tendency to extend the use of horizontal wells for improving the ultimate recovery of different recovery process, including waterflooding.

In this study, emphasize was given to several critical parameters affecting performance of horizontal injection wells in the highly heterogeneous Zone-17 of Hassi Messaoud (HMD) field in Algeria. These parameters are: position of the horizontal wellbore, perforated interval length and position, vertical to horizontal permeability ratio, and the optimum injection rate. The effectiveness of waterflooding using horizontal wells in this zone was examined in terms of sweep efficiency and ultimate recovery.

Horizontal injection wells have significantly increased injection capacity resulting in the ability to withdraw hydrocarbons from the reservoir at a higher rate. In Zone-17 HMD field, the injection/production rate can be increased by as much as four times without exceeding the fracture-parting pressure of the reservoir. Length and permeability of the perforated intervals, in heterogeneous reservoirs, have an important impact on the well injectivity and productivity. A relationship between these latter parameters has been developed.
The Value of Surveillance and Advanced Logging Applications for Brownfield Optimization
Authors: Akiode Bababola , Bhushan Vikas , Lee Robert , Mukerji Parijat , Zaouali Zouhir
Published: December 2007

There has been a tremendous growth in the number of high-angle and horizontal wells in the past decade. Coupled with the increase in water cut from various brownfield environments, these high angle wells present us with complex reservoir and production management challenges. Fit for purpose production logging technology is helping to provide a better understanding of fluid movement, enabling higher confidence decision making leading to successful interventions.

Production logging in high angle and horizontal wells that produce mixtures of fluid phases is challenging because of the associated complex flow regimes that radically change the physics and technology of measurement. Depending on the borehole deviation, the velocity and fluid holdup of different phases can change dramatically for a given flow rate.

We present examples that encompass various reservoir management objectives, well optimization and flow profiling. Surveillance logs were acquired in these wells to obtain key inputs for production optimisation, identifying bypassed oil and evaluating potential for additional perforations. Where necessary, production logs were integrated with pulsed neutron capture and spectroscopy measurements to enhance our understanding. In one of the examples, a compact integrated production logging tool comprising an array of spinners and holdup probes was conveyed with tractor in a horizontal well. Besides conveyance in this horizontal well, the challenge involved detecting minor oil entries in a very high water cut scenario. Two examples relate to the effective use of pulsed neutron spectroscopy measurements reservoirs. Finally one of the examples involves oxygen activation for positive identification of water movement behind pipe. Creating value through surveillance is the common thread that binds these well intervention examples together.
Development of the Gryphon Field Injection Wing—Technical Challenges and Risks
Authors: Hart N. , Ageneau G. , Mattson P. , Fisher A.
Published: December 2007

The Gryphon Field (UK Central North Sea) development commenced in 1993 with the successful exploitation of massive sand rich turbidite lobes of the Balder formation by horizontal wells. A component of small scale sand injection had been identified during appraisal and subsequent development but it wasn't until the acquisition of long offset simultaneous inversion seismic data in 2002 that the scale of the injection wing along the eastern edge of the field was appreciated. A full evaluation of the subsurface uncertainties led to the injection wing being matured as a development target although one which presented new challenges.

The main challenge proved to be locating and then geosteering through a three dimensionally constrained target with high lateral positional uncertainty and potential for wellbore instability. A multi-disciplinary team met this challenge with a combination of new technologies (e.g. prototype deep reading and azimuthal resistivity LWD tools) and the rigourous implementation of wellbore stability recommendations offshore.

Further technologies and strategies to mitigate these risks were introduced in the course of the drilling campaign (e.g. directional survey uncertainty reduction by In-Field Referencing and Dual Inclination techniques, landout strategies to address lateral positioning uncertainty, optimisation of well planning involving the multi-disciplinary team in a 3D environment and the use of low-rheology muds).

Production in some of the injection wing wells has substantially exceeded prediction whereas others have been more challenging to produce due to a faster than anticipated water-cut development. When averaged over all the wells, production targets have been exceeded.

The injection wing play has helped rejuvenate the field with seven wells drilled in the structure between 2004 and 2006 which, as of May 2007, have produced approximately 11 million barrels of oil and are contributing 80% of daily production.
Optimization of Tracer Test Design—Practical Applications
Authors: Meza Edgar , García Francisco , Muñoz Nancy , Reyes Carlos , Amador Arturo
Published: December 2007

A proposal to carry out a well to well chemical tracer test in the pilot area of a field with possibilities to implant an enhanced oil recovery (miscible CO2 injection) with two primary objectives:

Detect injecting wells that cause salted water leak at 200 meters deep in well C1001. Monitoring the injected water front behavior in each injecting well inside pilot area to define if there is vertical communication between two reservoirs.

Additional information could be possible to obtain with this tracer test as to identify the source of produced water in each producing well associated to each injecting well tagged, moreover, to measure irruption time, to identify channels or barriers that affect the fluid movement, to fix the main direction of front movement, to evaluate the front distribution inside each injection pattern in tested area and give support to field characterization in the pilot area.

To achieve these objectives, it was necessary evaluate the tracers program proposed that start with selection of injection scheme with six injecting wells tagged (one in reservoir A, four in reservoir B and one in both reservoirs) with six different chemical tracers.

We show the results of revision and analysis of each test include in tracers program and the investigation ratio adjustment used to monitoring protocol design, in which there were added several producing wells to be sampling and analyzing located inside the investigation ratio of each injecting well tagged with chemical tracer.
HP/HT Gas-Condensate Well Testing for Shell's Onyx SW Prospect
Authors: Fosså Arild , MacKenzie Derek , Steinveg Odd , Henderson Eric , Bosch Bart van den
Published: December 2007

This paper covers the HPHT Gas-Condensate Exploration Well, 6406/9-1 on the Onyx SW prospect of the Norway Sea in the late spring of 2005 (Figure 1 and 2). The well test design and execution is presented in the paper, including; up front planning, job design, technology selection and review of the test results vs. the objectives for the well test. The paper also addresses how health, safety and environmental considerations were handled.

Traditional well testing methods and equipment have evolved over the years, adapting to changing requirements. This has resulted in requirements for more complex data gathering over a shorter time with much stricter environmental and safety constraints. Coupled with increased needs for more accurate reservoir data for prospect evaluation, this has put a higher emphasis on upfront planning and improved technical performance together with extensive use of advanced fluid data gathering methodologies.

This paper demonstrates how the above was addressed for the Onyx SW and how the results compared with the set goals. The application of the latest technologies in Gas-Condensate well testing was used on this job. Experiences from this were later used as the basis for other gas-condensate prospects, including those in the Russian sector of the Barents Sea.

This paper focuses in particular on Fluid Sampling, Surface Well Testing and Subsea equipment. As several service companies were involved on this particular job, we have only included some general and limited content for the other services involved.
Use of Streamline Simulation for Waterflood Management in Naturally Fractured Reservoirs
Authors: Iino A. , Arihara N.
Published: December 2007

Waterflood management for naturally fractured reservoirs is a difficult task due to complex fluid behaviors between fracture and matrix. The streamline model is particularly useful for assessing the individual contribution of injectors to each producer accounting for inter-porosity transfer.

A simulation model for naturally fractured reservoirs was developed aiming at improved waterflood management with the use of the concept of streamline-derived injection efficiency (IE). Waterflooding in the dual-porosity dualpermeability system is first modeled by the streamline approach employing the operator splitting technique to account for gravity and transfer between fracture and matrix. IEs for individual injector-producer pairs are determined from saturation profiles on streamlines in both continua after evaluating transfer effects.

The model is capable of performing the reallocation of injection water to improve oil recovery from fracture and matrix. The model can also be applied readily to field-scale simulation because of rapid calculations with the streamline method.

This paper describes the methodology and implementation of IE-based injection-rate control for dual-porosity dualpermeability reservoirs and demonstrates the applicability by simulation examples. Application of the method makes it possible to evaluate the dynamic efficiency of the injected water for individual injector-producer pairs. Based on the computed IEs, reallocation of the injection rate among the injectors is made so that more oil in matrix and fracture is displaced by injected water. The examples showed usefulness of the method for naturally fractured reservoirs of highly heterogeneous matrix and fracture properties.
Waterflood Performance in a Depleted Fractured Chalk Reservoir
Authors: Griffin Tim , Best Kevin , Thingvoll Torgrim , Stockden Ian , Tjetland Gunnar
Published: December 2007

Valhall is a fractured chalk reservoir in the Norwegian sector of the North Sea which has been producing under compaction and solution gas drive since 1982. A water injection pilot led to sanctioning of the Valhall Waterflood Project which began injection in the crest of the field early in 2006. The predictions of Valhall waterflood performance covered a wide range of parameters that included fault and fracture pattern, water chemistry, compaction due to depletion and water weakening, 3 phase relative permeabilities, scaling and souring that all will impact sweep, recovery and well integrity.

To gather the key data required to make decisions in waterflood planning in the correct time frame, a comprehensive surveillance plan was drawn up. This included open and cased hole logging data, a dedicated monitoring well, time lapsed seismic and injection / production well performance data. This data is also used to manage short term waterflood issues associated with potential water breakthrough, monitoring pressures and managing the water chemistry.

Early data has revealed variability in the waterflood response in the crest. Two types of responses have been observed, a fractured zone and a more matrix dominated zone. Understanding these variations is key for placement of future injectors and for the expansion and optimization of the Valhall Waterflood Project.
Brenda Field Development: A Best Practice in Horizontal Well Placement Leading to Optimal Reservoir Drainage
Authors: Halward Ken , Emery Joe , Christensen Rod , Bourgeois Daniel , Skinner Grant , Tribe Ian
Published: December 2007

In 2006, Oilexco North Sea Limited developed the Brenda field in the Central North Sea. A total of over 8000 ft of horizontal section has been drilled in three horizontal production wells, all within Palaeocene-aged Balmoral turbidite sandstones below a Sele shale cap rock. To maximize reserves recovery, the horizontal drainholes not only had to cut as much of the good reservoir sand as possible, but as the Brenda field depends on water drive as its main production mechanism it was essential the wells were placed as close as possible to the top of the reservoir to ensure a greater long term field life and given the thin oil column, reduce the volume of attic oil. Generally the location of the top reservoir is visible on seismic but with significant sub-seismic variations in the top reservoir topography. Therefore to help optimal well placement, Oilexco used a new deep and directional LWD measurement in the Bottom Hole drilling Assembly in order to map the relative position of the drainhole to the overlying roof shales. As the reservoir top and internal shale layers were mapped, geosteering personnel had the ability to make changes to the directional plan to allow the well to be placed in the optimal location, at the top of the reservoir, often within 2 ft of the roof without reservoir exit.

The Brenda wells have proved to be well positioned using these new geosteering techniques. Initial flow testing of the wells was very positive with combined rates of over 26,400 BOPD with minimal reservoir drawdown. It is expected that the use of the new logging methods will result in more effective and uniform drainage of the Brenda reservoir sands, while minimizing the chance of premature water influx.
Accurate Structural Dip Interpretation in Real-Time Logging While Drilling: A Case Study From a Highly Deviated Gas Storage Well, Po Plain Basin, Northern Italy
Authors: Morris S. , Glass C. , Zurcher D. , Maletti G. , Borghi M. , Marzorati D. , Barbieri E. , Scanavino D.
Published: December 2007

In a recent well, drilled in the Po Plain basin of northern Italy, a high resolution logging-while-drilling (LWD) electrical image was acquired to undertake real-time structural analysis over a thinly bedded mixed sandstone sequence within a highly deviated gas storage well. An objective was to validate the accuracy of the real-time high resolution images for future geosteering applications in a complex area with many petrophysical uncertainties and operational limitations.

The operators identify that the right measurements to support high resolution structural dip evaluation in real-time will allow geosteering uncertainties to be reduced further, and that this can result in better decision-making and ultimately optimal payzone penetration.

Real-time dip analysis from the electrical image has been favourably compared with results from the memory data and other imaging devices in the same BHA (gamma ray and density) and also with wireline electrical images from the same well. This case study also presents advanced sedimentological and structural applications of LWD electrical images and highlights imaging resolution capabilities now possible while drilling.