bluuebunny/crossref_metadata_2025 huggingface dataset:
Use of 3D Seismic Data for Hazards and Site Assessments, Pipeline Route Planning, and Preliminary Engineering Design
Authors: Baerenwald Paul D. , Ruckman P. J.
Published: December 2007

The advantages of 3D seismic data over conventional 2D geophysical data include: high-density data coverage, improved spatial delimitation of geologic and stratigraphic features, and the ability to visualize geologic, stratigraphic, and structural features in ways not possible with 2D seismic profiles. The widespread availability of 3D exploration seismic data has ushered in a new approach to deepwater hazards and site assessments as well as regional development studies. With the advent of high-powered desktop computers, new software packages, and advanced analysis techniques, these data are now being used for more than the exploration of hydrocarbons, particularly in water depths greater than about 200 m.

Exploration 3D data are routinely used to identify and avoid unfavorable drillsites and pipeline routes, thus reducing overall costs. Whereas exploration 3D seismic data generally have sufficient resolution to identify significant drilling hazards and for preliminary pipeline route planning, these data are not adequate for final structure, site or pipeline route selection or for detailed stratigraphic characterization needed for design. In these cases, high-resolution site- and route-specific surveys are still required.

The advantages of 3D data are now also available in high-resolution geophysical surveys. These data reduce the need for repeated surveying of the same area and provide details unseen on conventional exploration data. A single high-resolution 3D data set can be used for multiple applications throughout the exploration, production, and development process. These data are used for shallow and intermediate exploration, analyses of seabed topography, geohazards assessments, understanding of complex structural and stratigraphic conditions, well planning, and field development. When integrated with geotechnical soil boring data, high-resolution 3D data provide a detailed understanding of stratigraphic variability necessary for final structure siting and design.
A Different Approach to Solving Mud-Related Hole Problems
Authors: Chamberlain D.E.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

In this paper is discussed a method of analyzing and solving hole problems based on data received from mud check sheets and annular flow calculations. Included is a basic review of the eleven functions of mud required to drill the hole to desired depth and size at minimum costs. Several tests and system checks to insure that a selected mud system is fulfilling its functions are included.

TEXT

Matching annudar flow (hydraulics) programs with mud programs is very valuable in obtaining a successful solution to hole problems. How many times, in spite of remedial action, does a hole problem persist, or another problem arise shortly after such action has been taken? Analysis of the problem may be based on annular flow, which is the science of fluids in flow, or on drilling muds, or a combination of both. Analyzing both these data will help solve the problem itself rather than treating only the symptoms resulting from the problem.

The following is a basic review of the functions of a drilling mud and how these functions are determined from mud sheets and annular flow calculations. To begin, the mud should be accurately tested to determine its composition and chemical properties. Mud is composed of a liquid phase, active solid phase, and inert solid phase. The liquid phase may be freshwater, saltwater, or oil which may contain various soluble or partially soluble chemicals that are considered part of the composition. Active solids are usually commercial clays used as the primary source for rheological and filtration control, and hydratable clays and shales from drilled formations. They are chemically treated to control the properties of the drilling mud.
How To Enhance the Recovery of Intermediate Components of an Extremely Volatile Oil
Authors: Palasthy Gy. , Papp I. , Lakos B. , Tromboczky S.
Published: December 2007

An enhanced recovery process suited to a hydrocarbon reservoir containing extreme quality crude oil is presented in the case history. At the initial pressure and temperature conditions (pi=169 bars and ti= 92 °C), the oil reservoir volume factor is: Boi=3.94 m3/m3, the dissolved gas content: Rsi=712 m3/m3 and the specific gravity of the crude only ρ =0.728 t/m3 (63 API).

The reservoir has been produced since 1984 and Eo= 37 % recovery has been reached, while the pressure has declined only by 5 % because of the active water drive. The further production strategy was elaborated with a 3-D, full field composition simulator by an integrated team between 1996-98.

The forecast calculations show that Eo=48 % final recovery can be reached for the individual components in the reservoir with strong water drive. For further recovery enhancement, the best dissolved - both from technological and technical aspects - seemed to be a dry gas injection process which would cause 10-13% additional recovery in the C3-C6 components of the crude oil.
Influence of Nonuniform Initial Pressure Distribution in Well Test Data
Authors: Sampayo-Trujillo Antonio , Camacho-Velázquez Rodolfo
Published: December 2007

Most of the procedures available in the literature for well tests analysis assume a uniform initial pressure distribution. In this paper the influence of a non-uniform initial condition in pressure data is presented.

Several solutions, which consider a non-uniform initial distribution and different conditions at the inner and outer boundaries, are presented. These solutions were obtained by using a combination of Laplace transformation and Green's function methods. Integral equations relating the well response to the initial distribution function are obtained. These equations, which represent inverse problems, are solved recursively by using Backus and Gilbert solution.

Numerical experiments of the pressure response in homogeneous and naturally fractured reservoirs with different initial pressure distributions are presented. The theory and numerical results are compared and found good agreement demonstrating the applicability of the proposed method.

For radial systems it is found that the semilogarithmic straight line is not generally evident during the transient period. Also during the boundary dominated flow period, with no-flow outer boundary, it is found that an additional pressure drop is present for the case of a non-uniform initial distribution. An expression for this additional pseudo-skin is provided.
Complexity of Well Testing Analysis of Naturally-Fractured Gas-Condensate Wells in Colombia
Authors: Pinzón Claudia L. , Chen Her-Yuan , Teufel Lawrence W.
Published: December 2007

Reservoir management is difficult for several gas fields in the flanks of the fold-thrust belt of the Eastern Cordillera of the Middle Magdalena Valley, Colombia. Technical complicating factors include (i) complex geology (faulting, naturally fractured), (ii) high tectonic stresses (> 1.0 psi/ft), (iii) high-angle formation dip (> 60°), (iv) overpressure (> 1.0 psi/ft), and (v) gas condensation. Due to the unusual stress/tectonic environment, a potential impact to reservoir performance is the stress-sensitive permeability (permeability reduction-rebound induced by fluid withdrawal-injection). Interpretation of well testing thus is challenging because of the combined effects from the above factors.

This paper presents an analysis of a field isochronal test. The effect of stress-sensitive permeability on well test response is emphasized through numerical simulations. Other factors complicating the well-test interpretation are also discussed. Pressure derivative analysis is shown to be very useful in identifying the permeability variation. The logarithmic slopes basically reflect the combined variations of permeability, producing thickness, flow rate, and fluid properties. Natural fracturing, gas-condensation, high gas rates, and stress-sensitivity permeability will contribute to the changing slopes of pressure response. The impacts are essentially reflected by the magnitudes of near-wellbore skin and reservoir permeability. Guidelines useful in identifying stress-sensitive permeability from well testing are proposed.
Three-Phase Discrete Flow Network Simulation Matches Vertical and Horizontal Completion Efficiency
Authors: Button P. M. , Wadleigh E. E.
Published: December 2007

An innovative approach has been used to model flow through discrete fracture networks in a massive carbonate reservoir in order to understand and predict performance of vertical and horizontal well completions. This approach focuses on completion effectiveness and the influences that fractures have in a three-phase gravity influenced flow system. The model is set up as a dual porosity, dual permeability simulation of a discrete fracture network of high permeability grid blocks capable of modeling three-phase flow. This model reveals the dominant factors controlling well life cycle performance demonstrated in the Yates Field Unit

Natural fracture networks dominate flow throughout the reservoir with added economic significance to completion efficiency. Therefore 3D discrete fracture network (DFN) models based on connected-fracture orientation from FMI logs and flow surveys have been used as a basis for constructing the 3-phase simulation grid. The differences in mobility between the three phases result in abnormally shaped gas-oil and water-oil contacts as drawdown is applied. As the fracture oil column depletes, oil mobility reduces with the decrease in effective fracture connection to the outlying oil column. This loss of oil mobility through phase dis-connection in flow conduits has not been the focus of prior studies. The simulator has successfully generated production profiles similar to those observed in field performance data. This wellbore simulation has been used to develop a strategy for optimal completion performance and placement.
Applicability and Rate Sensitivity of Several Up Scaling Techniques in Fractured Reservoir Simulation
Authors: Talukdar M. S. , Banu H. A. , Torsæter O. , Kleppe J.
Published: December 2007

This paper presents the applicability/validity and rate sensitivity of several conventional up-scaling techniques in fractured reservoir simulation. Three different models have been developed and simulated using Kyte and Berry, Pore Volume Weighted, Weighted Relative Permeability, and Stone type pseudos at different rates and with different oil-to-water viscosity ratio.

From the results it can be concluded that these techniques may be used in fractured reservoir simulation in order to reduce number of simulation grids as well as to synthesize details of small-scale fluid mechanics and reservoir heterogeneity. They may or may not be rate sensitive depending on the model type.
Core Analysis Techniques, Case Histories and Interpretation of Data For the Rocky Mountain Region
Authors: Harris James D. , Keelan Dare K.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

Reasons are presented for securing core analysis data that furnish porosity, permeability, residual fluid saturations and lithology. Types of core analysis are briefly reviewed. Changes in in-situ fluid saturations resulting from flushing during coring and fluid expansion during transport of the core to the surface are discussed. Precautions in core sampling, handling, packaging and preservation are briefly reviewed. Interpretation of data, using actual case histories of formations in the Rocky Mountain Region, are presented to illustrate gas-oil contacts, transition zones, oil-water contacts and coning of gas and water. Also, a comparative example of conventional (plug type) versus whole core (full diameter) analysis is presented to illustrate the importance of whole core analysis in assessing productivity of fractured reservoirs.

Introduction

Cores are taken and analyzed to permit direct examination of samples of the section so that lithologic changes can be correlated and evaluated with the subsequent core analysis data and down hole logs. Cores are analyzed to permit a direct determination of the petrophysical characteristics of the formation. These characteristics include porosity, permeability, residual fluid saturations, lithology, grain density, cation exchange capacity, electrical and elastic properties, capillarity and relative permeability. All other methods of evaluating these properties are indirect. Table No. 1 summarizes routine core analysis data and its use.

TYPES OF CORE ANALYSIS

Core analysis has evolved into two major types related to the size and portions of the core analyzed, as various formations require different analytical techniques to obtain valid data.
Fracture Characterization a Key Factor in Yates Steam Pilot Design and Implementation
Authors: Snell J. S. , Wadleigh E. E. , Tilden J.
Published: December 2007

The successful design and implementation of any improved oil recovery project in a fractured reservoir depends on an accurate characterization of the fracture system. This is especially true in a steam pilot project currently underway in the Yates Field of West Texas. This pilot will assess the economic viability of accelerating gravity drainage in the gas cap of the fractured San Andres reservoir. From the conceptual phase of the project through implementation and monitoring, fracture characterization in the pilot area has been critical to pilot design and success. Key decisions have depended on an accurate assessment of fracture density, orientation, flow capacity and connectivity to other portions of the reservoir. Many geologic and engineering methods have been employed to understand the fracture system. Flexure mapping, tracer testing, pressure interference testing and reservoir simulation were employed in the design phase of the project. Fluid sampling and passive microseismic monitoring have been employed to monitor the project. This paper will discuss each of these methods, field results, and key decisions that were based on the analyses.
A New Hydrodynamic Washpipe Sealing System Extends Performance Envelope and Provides Economic Benefit
Authors: Morrow W. C. , Drury R. F. , Dietle L. L. , Kalsi M. S.
Published: December 2007

A patented washpipe assembly has been developed that improves the economics of high speed, high pressure drilling by minimizing tripping frequency and downtime associated with conventional washpipe maintenance. The assembly addresses wear mechanisms associated with high pressure, dynamic runout, and high rotational and surface speed by employing hydrodynamic lubrication, pressure staging and component articulation. No external power sources or controls are required. This has totally changed the operational characteristics and failure dynamics of swivel sealing. This paper describes the operating principles, field performance and significant economic benefits of the new assembly.
Application of Metal-Bearing Seal Roller-Cone Bit Reduces Rig Time/Drilling Costs in Green Canyon, Deep Water Gulf of Mexico
Authors: McLeod Scott A. , O'Grady Thomas T. , Sullivan Eric C. , Mason John S. , Lin Chih
Published: December 2007

The application of a metal-bearing-seal roller-cone bit in Green Canyon, deep-water Gulf of Mexico has had a beneficial impact on drilling costs. Improvements in seal reliability (one million bit revs or 1000 krevs without seal failure are common) and cutting structure durability have resulted in more time "on bottom" and have permitted the operator the confidence to apply the steel-tooth roller-cone bits to directional work where polycrystalline diamond compact (PDC) bits were once required.

Typically, the operator's applications are deep and directional and water-based fluids are preferred in the upper hole section while synthetic mud is used deep in the wellbore. Periodically, the operator also uses a steerable-ream-while-drilling (SRWD) system. In all cases, the operator strives to maximize "hours on bottom".

The roller-cone bit's resistance to "balling" in water-based muds (WBM), its desirable steerability characteristics and the option to use the bit in service with the SRWD, coupled with its improved reliability, make it the appropriate tool for the application. The authors will document rig cost savings ranging from $150,000-$300,000 US in some applications.
Assurance Increased for Drill Cuttings Re-Injection in the Panuke Field Canada: Case Study of Improved Design
Authors: Guo Q. , Dutel L. J. , Wheatley G. B. , McLennan J. D. , Black A. D.
Published: December 2007

Disposal of oil-contaminated cuttings has become increasingly important from both economic and environmental perspectives. Re-injection through hydraulic fracturing can provide a zero discharge solution and eliminate future cleanup liabilities. The development of best practices and practical solutions for predicting fracture growth during slurry injection has accelerated the economic disposal of oily cuttings from drilling operations.

One such case is for Panuke wells, in Nova Scotia, Canada. For sections deeper than 1290 m MD, these wells are drilled with oil based mud. In the past, drilling waste was injected into an existing well, Well PI-1. A total cuttings slurry volume of 96,000 bbls had been injected through casing into well PI-1 before an additional well was planned in early 1999. Well PP3C was identified as a candidate injection well through the 11¾" × 9 " casing annulus. In order to assure the containment of fractures arising from injection, investigations were conducted on the design of the injection process using a fully three-dimensional hydraulic fracturing simulator. This paper assesses the affects of formation layering, varying permeability and elastic modulus, injection rate, and other operational procedures on the injection fracture geometry and containment.

Significant to the injection recommendations were lessons learned from a recent joint industry project on ‘drilling waste disposal’ (DEA #81). The ability to verify multiple fractures in DEA #81 from post laboratory test examination suggests that the analyses and design are adequate to assure safe containment of injected drill cuttings. The case study showed that interaction among the various factors can result in very complex fracture geometry and a true three-dimensional fracturing simulator must be used to assess fracture containment. The results provide insight into best practices for the containment of fractures, designs for successful re-injection, selection of candidate injection zones, and quality assurance.
Differentially Stuck Pipe: Early Diagnostic and Solution
Authors: Santos Helio
Published: December 2007

Problems with differentially stuck pipe account for huge losses in the oil industry all over the world. Being able to minimize the risk of getting stuck while drilling has been the goal recently. However, some misunderstanding and misinterpretation of current laboratory and rig tests have led operators to apply the wrong solution to the problem. This paper initially addresses how the drillstring gets differentially stuck and the main related mechanisms. The old concepts and ideas are revised here on the basis of new drilling fluids being used, especially the ones with low solids content. The simplest solution for minimizing the risk of getting stuck is described, as well as some field indications of how the problem can be detected at an earlier stage. The paper finally shows the importance of changing the way some tests are conducted today to clearly quantify the risks involved in any drilling operation.
The Mechanical Earth Model Concept and Its Application to High-Risk Well Construction Projects
Authors: Plumb Richard , Edwards Stephen , Pidcock Gary , Lee Donald , Stacey Brian
Published: December 2007

Many of today's well construction projects are technically and economically challenging. Examples include deepwater exploration wells in the Gulf of Mexico, offshore field development projects such as Hibernia, Newfoundland, Canada and onshore field development projects in tectonically active regions such as the Cusiana field in Colombia. Minimizing non-productive time associated with wellbore instability and unexpected pore pressure regimes reduces the risk of dangerous accidents and is required to complete the well on time and within budget. Minimizing non-productive time is a complex task that requires thorough pre-spud planning to identify drilling risks and geological hazards and to develop contingency plans for handling those risks. Building a mechanical earth model during the well planning phase and revising it in real time has proven to be extremely valuable in delivering complex wells safely while minimizing unplanned well construction costs. Monitoring and revising the model while drilling requires geomechanics expertise, teamwork, data management and excellent communications among service companies and their client.

This paper defines a mechanical earth model, explains why it is important, how it is developed and how it is applied to well construction and field development. We will discuss sources of information and the multi-disciplinary team approach required to: generate, revise and maintain an earth model. Three examples of the application of the earth model concept are discussed.
New Cement Systems for Durable Zonal Isolation
Authors: Le Roy-Delage S. , Baumgarte C. , Thiercelin M. , Vidick B.
Published: December 2007

In this paper we present new cement systems where the value of elastic parameters are specified to meet the requirement for long term mechanical durability. These systems can also contain expanding additives leading to an optimum configuration to prevent loss of zonal isolation due to change of downhole conditions. The advantages of these systems are demonstrated in field test cases where the cement sheath behavior as a function of changes of downhole conditions is modeled to determine whether damage could occur or not.
New Model of Pressure Reduction to Annulus During Primary Cementing
Authors: Zhou Desheng , Wojtanowicz A. K.
Published: December 2007

Annular pressure reduction during cementing is the major factor causing annular gas flow. It has been accepted and proven experimentally that the pressure reduction phenomenon results from the shear stress opposing downward motion of slurry undergoing to volume reduction. Mathematical models have been proposed to describe this process based on the gel strength (or shear stress) development in time. However, the models can only simulate pressure reduction process observed in the lab where compressibility of the system is very small. The models can not explain the variety of pressure reduction patterns observed in the field operations when time-dependent effects of compressibility significantly contributes to the process.

The paper presents a mathematical model combining the effects of gel strength, volume reduction, and compressibility on pressure loss in the cement column. Results from the model, shown in the paper, compared very well with the data from the laboratory and in field tests. The simulated results explained discrepancies in the pressure loss patterns observed in these tests. Main contribution of this study is to quantify the interaction between friction and de-compression mechanisms and their extend in the cement column after placement.
A Unique Cost Effective Technique for One Trip Selective Gravel Packing Over Multiple Zones: Dacion Field Case Study
Authors: Marshall John , Obianwu Chike , Tibbies Raymond , Vargas William
Published: December 2007

Selective gravel pack completions of multiple zones present the oil industry with major challenges and expenses. Current practices have two key problems associated with them: (1) they are limited to zones separated by 30 to 50 feet (depending on the treatment type) due to the length of the assemblies (2) they have proven to have a higher risk of installation failure.

This paper describes equipment and procedures for gravel packing multiple zones in a single completion with total zonal isolation for spacing as small as 5 feet. Zones can be produced either separately or co-mingled. Risk of execution failure is significantly lower than with conventional stacked packs. Production data is presented which verifies complete zonal isolation, improved productivity, and reduced costs from this technique.
Advanced Transient Simulator for Studying Shallow Gas Blowouts
Authors: Rath J. S. , Podio A. L.
Published: December 2007

Two wellbore hydraulics simulators (KICK1 and COMBOF2,3) were modified to simulate high flow rate from overpressured high permeability formations in order to study the necessary reaction time to avoid a blowout event. This paper describes the computational approaches and results of calculations using these two different numerical wellbore hydraulic simulators. The coupling of the wellbore and the reservoir model is an important aspect of these simulators. The wellbore is coupled to an overpressured highly permeable zone through the use of an influence function. An influence function is an externally generated linear system whereby a change in pseudo-pressure yields a change in cumulative gas influx (or mass flow rate). This influence function can be generated from a suitable two-phase flow reservoir simulator, prior to the wellbore hydraulic simulator calculations. The KICK numerical simulator uses a moving boundary approach to more accurately describe the multi-phase fluid mixing and transport during drilling activities. Both simulators were used to analyze potential blowout scenarios at the Waste Isolation Pilot Plant (WIPP) transuranic waste (TRUW) repository.
Application of Novel Technologies in the Design and Engineering of Synthetic-Based Mud Used to Drill and Complete Horizontal, High-Temperature/High-Pressure Wells in the Central North Sea, Marnock Field
Authors: Swanson B. W. , Munro R. , Sanders M. W. , Kelly R.
Published: December 2007

The Marnock field is located in the Eastern Trough, UK Central North Sea, some 130 miles east of Aberdeen in water depths of 300 feet. The reservoir is Triassic fluviatile sandstone. Reservoir fluid is gas condensate at a temperature of 310°F and pressure of 9100 psi at 11500 feet (3500 metres) TVD.

The main risks of drilling the reservoir sections and in running the sand face completions for Marnock come from the combination of high permeability and horizontal well geometry with HTHP conditions. Hydrostatic profiles change constantly with operation due to temperature changes and this increases the risk of well control incidents and lost circulation. Stuck pipe and stuck screen incidents are also statistically significant in these wells.

In addition to drilling risks, post-well intervention is costly, high risk, and technology-limited due to the horizontal HTHP conditions. Therefore, the prevention of formation damage and completion impairment has to be addressed in the drilling phase. Decision making, in determining the balance of risks to productivity requires a full understanding of all the factors affecting drilling, completion and production.

With these operational difficulties, novel measurement technologies and focused mud management were used to mitigate the risks associated with barite sag, differential sticking, insufficient hydrostatic, formation damage and ECD induced losses. This paper highlights the techniques used on Marnock to successfully manage mud to drill and complete the wells.
World's First Downhole Flow Control Completion of an Extended-Reach, Multilateral Well at Wytch Farm
Authors: Gai H. , Davies J. , Newberry P. , Vince S. , Al-Mashgari A.
Published: December 2007

The world's first down hole flow control completion of an extended reach, multilateral well was implemented, achieving all objectives without any safety incident. The economics indicators are favourable.

All the key parts of the Projects are captured here in a structured manner and in some detail. A great deal of learning has been covered, with an intention to cater for a variety of engineers and co-ordinators.

After introductory notes including the challenges, the completion objectives were set out to which the remainder of the paper ties back. The mechanics of the Project was described next, i.e. how the completion looked and how things were done. Considerations of key engineering issues were detailed, demonstrating a sound design. Then some of the key processes in managing the Project were shared, touching on a range of topics from common sense practices and a novel economic evaluation tool to risk and crisis management. Lessons learnt revealed some most astonishing battles against potential disasters and how the Team came out stronger.

The main conclusions included that downhole flow control can be achieved safely, fittingly and cost-effectively, and that the techniques developed and processes used in managing the project by the Team have shown to work well.
Use of a Rotary Steerable Tool at the Valhall Field, Norway
Authors: Kinn Sigurd , Allen Peter , Slater Martin
Published: December 2007

The overburden at Valhall consists of weak and partly fractured shale contributing to wellbore stability problems while drilling. To reduce the stability problems it is desirable to maintain a constant pressure on the formation, but this is not possible when drilling and tripping in a well. However, it is still important to minimize the pressure variation. An important factor here is to reduce the Equivalent Circulating Density (ECD) fluctuations when circulating the drilling fluid.

Rotary steerable systems have been used on Valhall to improve hole cleaning and also to improve wellbore stability by keeping the ECD as low as possible while drilling.

This paper forms a case history of several rotary steerable tool runs on the Valhall field, offshore Norway. The paper will, as an introduction, briefly discuss the different steering principles of available rotary steerable systems.

In most fields the focus has been on using rotary steerable tools in the reservoir section; however, on Valhall they have been used in the overburden section. The reason for concentrating on the overburden at Valhall is because of the weak and fractured shale with it's wellbore stability problems. The paper will concentrate on the particular rotary steerable system used on Valhall, the Automated Guidance System or AGS Tool, which has been used to drill 12-1/4" × 13-3/4" holes.

To be able to drill this hole size below a 13-3/8" casing string, a 12-1/4" bit was used below the Tool and a standard underreamer was initially used above. However in the two most recent wells, a specially designed near bit reamer, was used to drill the oversized hole.

The automated guidance system has been used on 5 wells in the Valhall field and has made a total of 8 runs. Although none of these runs achieved the casing point, two of the runs set world records at the time, of more than 2000 m, and were regarded as major successes. Several runs were also planned at the limit of the Tool's specification. These runs were regarded as a combination of commercial and tool development runs, and were as such also considered successful.

Comparisons will be made between the results from the different runs and the planned wellpaths. Also the actual automated guidance system wellpaths and similar mud motor runs will be compared in order to demonstrate the enhanced directional performance of the AGS Tool.
Eccentric Tool Increases Liner Size Capacity in Challenging Salt Dome Application Allowing Longest Horizontal Well in Gulf of Suez
Authors: Billman William J. , Brown L. A. , Zaki Mohsen
Published: December 2007

This paper describes the successful use of eccentric tools to solve a variety of complex downhole problems associated with drilling through flowing salt formations in the Gulf of Suez. The tool allows simultaneous reaming and drilling with steerable assemblies (SRWD).

The SRWD technology was applied in two intervals on well A-19, East Zeit Bay Field, as insurance against hole problems caused on the previous wells by salt mobilization and saltwater flows. On well A-19, the operator had to decide either to drill with a large casing program or use the underreaming technology while still drilling an economic well. Additional problems involved drilling through large salt sections, possible saltwater flows, interbeded hard limestone/anhydrite sections and an aggressive directional wellbore design.

Without SRWD technology, the operator would have to drill a well using a large hole design, which was complicated due to the platform considerations, casing inventories available, and the higher costs associated with the increases of mud volumes, and decreased penetrations rates. The operator was able to steer the 14-inch SRWD tool to keep the wellbore on track at 38 degrees to the planned casing point. The lower 12-1/4" build section was drilled from 38 degrees to 67 degrees while turning the hole from an azimuth of 108 degrees to 123 degrees with no major problems associated with the SRWD tools.

The authors will discuss the optimization of the well design, the technology of the SRWD and the close cooperation between all the service companies required to help the operator drill the longest horizontal well in the Gulf of Suez without sacrificing cost per foot, and making a successful well.
Commercial Pilot Test of Polymer Flooding in Daqing Oil field
Authors: Guo Wankui , Cheng Jiecheng , Yao Yuming , Li Chuanhong , Li Wenxue , Li Qun , Liu Junde , Wu Junzheng
Published: December 2007

The commercial pilot test of polymer flooding in Daqing oil field began in January 1993, and finished in October 1998, which has been near 6 years. The test is the first commercial pilot with large scale to enhance oil recovery in China. Accumulations 6422t of pure polymer were injected.

Comparing with water flooding, the results of polymer flooding are successful, recovery incremental oil 123t for each ton polymer. On the basis of the analysis of reservoir characteristics, water flooding history and the polymer performance, the paper describes the production regularity of polymer flooding, and discusses various factors, which have great influences on polymer flooding. The data of reservoir core, before and after polymer injection, indicated that polymer flooding not only could enlarge swept volume but also increase recovery, thickness of watered out of reservoir increasing 28.9%, recovery 9.5%. At present, polymer flooding has been widely used in Daqing oil field.
Transient Foam Flow in Homogeneous Porous Media: Surfactant Concentration and Capillary End Effects
Authors: Apaydin O. G. , Kovscek A. R.
Published: December 2007

Foaming injected gas is a useful and promising technique for achieving mobility control in porous media. Typically, such foams are aqueous. In the presence of foam, gas and liquid flow behavior is determined by bubble size or foam texture. The thin-liquid films that separate foam into bubbles must be relatively stable for a foam to be finely textured and thereby be effective as a displacing or blocking agent. Film stability is a strong function of surfactant concentration and type. This work studies foam flow behavior at a variety of surfactant concentrations using experiments and a numerical model. Thus, the foam behavior examined spans from strong to weak.

Specifically, a suite of foam displacements over a range of surfactant concentrations were monitored in a roughly 7 μm2, one-dimensional sandpack using X-ray computed tomography (CT). Sequential pressure taps were employed to measure flow resistance. Nitrogen was the gas and an alpha olefin sulfonate (AOS 1416) in brine was the foamer. Surfactant concentrations studied varied from 0.005 to 1 wt%. Because foam mobility depends strongly upon its texture, a bubble population balance model is both useful and necessary to describe the experimental results thoroughly and self consistently. Excellent agreement is found between experiment and theory.
Waterflood Surveillance and Supervisory Control
Authors: De Asoke , Silin Dmitriy B. , Patzek Tad W.
Published: December 2007

A successful waterflood depends on the proper operation of individual wells in a pattern, on maintaining the balance between water injection and production over the entire project or field, and on preventing well failures. The problems with waterflood are further aggravated in tight rock, e.g., carbonate, chalk or diatomite, where injector-producer linkages, uncontrolled hydrofracture growth, and water breakthrough in thief layers are often encountered. For optimal operation of a waterflood, it is mandatory that field engineers routinely acquire, store and interpret huge amounts of data to identify potential problems and to address them quickly. The cost of an error can be extreme; failure of only one well may cost more than the entire surveillance-controller system described here. As in preventive health care, it is important to diagnose the problems early and to apply the cure on time. Our solution is to design a multilevel, integrated system of surveillance and control, which acquires and processes waterflood data, and helps field personnel make optimal decisions. Our upper-end systems will rely on the satellite radar interferograms (InSAR) of surface displacement and the new revolutionary micro-electronic mechanical systems (MEMS) sensors. Many intermediate configurations are also possible. In the near future, the next generation of smart, reliable and cheap sensors will revolutionize field operations of small independents and majors alike. We think that the impact of the new technology on the independents will be proportionally larger.
Assessing the Potential Redevelopment of a 1960's Vintage Oil Field
Authors: Weiss W. W. , Wo S. , Balch R. S. , Scott L. , Kendall R. P.
Published: December 2007

This paper presents the practical use of a public domain black oil simulator (BOAST) to formulate a reservoir redevelopment plan. The subject reservoir is the 3750-ft Penrose sand in the Eumont Pool located on the northwestern edge of the Central Basin Platform.

A small operator acquired the 22-well property from a major; as usual, interpretive information was not included in the well files. Therefore, reservoir characterization relied chiefly on public information (1960 vintage well logs and production/injection history). The old logs were evaluated by correlating them with a modern suite of logs to estimate the porosity, deep resistivity, and water saturation in three zones. The permeability was empirically predicted from the porosity and residual water saturation. Geostatistical maps based on the well values were used to estimate interwell gridblock properties required for simulation.

The initial reservoir characterization was modified while matching the 42 years of production/injection history of the individual wells. The primary and secondary history match suggested that ~10% of the original oil in place was recovered. The remaining 35 million barrels of oil is an attractive redevelopment target.

The calibrated simulation model was used to forecast continued operation as currently practiced. The performance of a new well with a 990-ft horizontal lateral was also evaluated, as well as the benefits of five different horizontal lateral completion strategies.
Verification of a Complete Pore Network Simulator of Drainage and Imbibition
Authors: Patzek Tad W.
Published: December 2007

Relative permeability and capillary pressure functions define how much oil can be recovered and at what rate. These functions, in turn, depend critically on the geometry and topology of the pore space, on the physical characteristics of the rock grains and the fluids, and on the conditions imposed by the recovery process. Therefore, imaging and characterizing the rock samples and the fluids can add crucial insight into the mechanisms that control field-scale oil recovery. The fundamental equations of immiscible flow in the imaged samples are solved, and one can elucidate how relative permeability and capillary pressure functions depend on wettability, interfacial tension and the interplay among viscous, capillary and gravitational forces. This knowledge enables one to answer questions such as: Can a change of injected brine salinity increase oil recovery and by how much? How much more oil would be recovered if advancing contact angles could be modified? Does water injection help to recover sufficiently more oil or is it just for pressure maintenance? How can water imbibition be enhanced and oil trapping limited? Can relative permeabilities be modified with a polymer or with a chemical agent, such as an electrolyte or surfactant? Can one rely on gravity drainage of oil films to increase recovery? These and many other questions may be answered through a combination of imaging and calculations presented here. This paper summarizes the development of a complete quasi-static pore network simulator of two-phase flow, "ANetSim," and its validation against Statoil's state-of-the-art proprietary simulator. ANetSim has been implemented in MATLAB® and it can run on any platform. Three-dimensional, disordered networks with complex pore geometry have been used to calculate primary drainage and secondary imbibition capillary pressures and relative permeabilities. The results presented here agree well with the Statoil simulations and experiments.
Use of Magnetic Resonance Imaging and Advanced Image Analysis as a Tool to Extract Mass Transfer Information from a 2D Physical Model of the Vapex Process
Authors: Fisher D. B. , Singhal A. K. , Das S. K. , Goldman J. , Jackson C.
Published: December 2007

The Vapor Extraction process (Vapex) is one of the few options for the recovery of huge resources available in the form of highly viscous heavy oil and bitumen. Vaporized hydrocarbon solvents are used to reduce the bitumen viscosity, which then moves towards the production well by gravity drainage.

IOR processes such as Vapex, have been difficult to study in the laboratory in any sort of quantitative way. The reason for this is that much of the information needed to get estimates of the mass transfer process is contained in the concentration gradients around the edge of the vapor chamber.

Conventional 2D visual models provide information only about the position of the vapor chamber and its advance. The use of Magnetic Resonance Imaging (MRI) as a tool to observe the movement of the vapor chamber not only includes its position but also gives useful information about the concentration gradients along the leading edge. Not only are the gradients measured, but the information is inherently 2D and, as such, with an appropriate mathematical model, a parametric description of the magnitude of the mass transfer can be defined in both the horizontal and vertical directions.

The use of phenomenological mathematical models in image analysis to describe the concentration gradient in functional terms allows the investigator to extract a great deal of parametric information from each experiment. This information includes enough spatial resolution to confirm that the movement of a point on the vapor chamber wall occurs in steps while at the same time, the width of the dispersion zone (where gas has diffused into the oil) increases before each step. These results have been obtained from a sand pack model saturated with Athabasca bitumen and propane as the solvent gas.

An analysis of two of these experiments (one dry sand and the other water saturated sand) has provided enough quantitative information to give solid support to the standard two step model of the Vapex process. The gas must first diffuse into the bitumen for some time to reduce the viscosity of the oil/gas mixture sufficiently so that in the second step the gravitational forces can overcome the capillary forces and allow the oil to drain down the vapor chamber wall. Additional information about the relative effect of connate water supports the observations that the process is faster when connate water is present. The role of asphaltene precipitation was observed but not quantified.
An Improved Method for Estimating Oil Reserves in Oil/Water Transition Zones
Authors: Fanchi J. R. , Christiansen R. L. , Heymans M. J.
Published: December 2007

The amount of recoverable oil in an oil-water transition zone depends on the distribution of oil saturation as a function of depth, and the relationship between initial oil saturation in the transition zone (Soitz) and residual oil saturation in the transition zone (Sortz). Traditionally, it is assumed that Sortz is the same as the residual oil saturation in the oil column (Sor) above the transition zone. However, data in the literature show that residual oil saturation depends on initial oil saturation. So, residual oil saturation in the transition zone (Sortz) should be a function of initial oil saturation in the transition zone (Soitz). The relationship between Sortz and Soitz is referred to as a trapped oil relationship.

The purpose of this paper is to show recent experimental corroboration of the trapped oil relationship and to demonstrate the impact of the trapped oil relationship on reserves determination in oil-water transition zones. Details of the experimental work may be found in Christiansen et al.,1 which discusses in depth the appropriate rock-fluid properties for characterizing transition zones. In this paper, the effect of the trapped oil relationship on reserves determination is shown in two ways: first, with an analytical model that shows the maximum possible incremental benefit of including the trapped oil relationship; and second, with an extended black oil simulation that incorporates the effects of relative permeabilities on reserves determination.