bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.