bluuebunny/crossref_metadata_2025_split huggingface dataset:
Techniques for Optimum Placement of Interval Control Valve(s) in an Intelligent Well
Authors: Ebadi F. , Davies D. R. 
Published: December 2007

AbstractIntelligent Well (IW) Technology improves well and field performance management by combining zonal production control using Interval Control Valves (ICVs) with the installation of flow monitoring devices. The "Added Value" for an IW is dependent on the number and location of the ICV controlled zones. Too many valves lead to unnecessary and excessive cost as well as the potential for reduced reliability. Too few valves will not provide sufficient flexibility for efficient control.We previously showed 1 that a minimum degree of un-even fluid-front progression needs to be induced in order for effective ICV control to be observed to "Add" sufficient "Value" to justify the costs and risks involved in installing this relatively new technology. ICV(s) can balance the fluid-front provided they are placed correctly. A typical example would be their installation across zones showing early water or gas break-though. This allows "Value" being "Added" to the reservoir management process by controlling the unwanted fluid. Optimum ICV placement requires prediction of these zones. The extent of reservoir layer / zone connection thus needs to be quantified. In practice, the available information is often limited to (local) information gained from measurement at or very near the wellbore during the drilling of the well, together with exploration seismic and (global) reservoir geological studies.A systematic study of the "Added ICV Value" for a range of reservoir models has been completed. The number of ICVs installed and the zonal length were varied. Emphasis was given to studying the more complex (e.g. channelised) reservoir models where prediction of the extent of reservoir layer / zone connection is more difficult.This study provides optimum ICV placement guidelines for different well and reservoir geometries with a variety of reservoir drive mechanisms. Results from this study highlight the importance of correct ICV placement. The results can be used as a screening and decision making tool for deciding on the optimum number of the ICV(s) and their placement.
Permeability Modeling in Porous Media: Setting Archie and Carman-Kozeny Right
Authors: Haro Carlos F. 
Published: December 2007

Abstract
Archie's empirical law constitutes the basis of quantitative Petrophysics; however, the physical significance of this law is poorly understood. The issue involves substantial uncertainty in oil in place. Similarly, Carman-Kozeny's (C-K) relation is source of several permeability models. C-K is derived from Poiseuille's equation, applicable in laminar-viscous-flow in straight-uniform non-communicating tubes. Neither C-K nor Poiseuille's formulae consider inertial accelerations, non-Darcy flow, caused by changes in either cross section or flow direction occurring in porous media. Implications include sizeable limitations in permeability modeling.
Suitable hydrodynamic and electrical models can be created using fluid mechanics analytical methods. The models delineate the velocity and electrical potentials, streamlines and controls, represented by C-K and Archie's equations. This approach theoretically verifies both relations and reveals that:
Assisted by the boundary layer theory, fluid circulation and permeability are optimally modeled invoking superposition of viscous and inertial regimes in nozzles, throats, diffusers, pipe networks, and arrays of solid particles. These hydraulic components, once assembled, emulate interconnected pore throats and bodies very well. The flow around a corner solution of Laplace's equation characterizes the changes in fluid and electric flow direction, mainly occurring in the pore bodies. The solution precisely defines rock frame, conductive phase, and hydraulic tortuosities, enabling direct ties to pore geometry. This facilitates permeability calculations utilizing the "perfect permeability transform" procedure.
The aim of this work is to show how Archie's law ceases being merely empirical and C-K becomes thorough, thus gaining a full physical conception of their power law behavior. As a result, revised Archie's and C-K relations are proposed for water saturation and permeability computations. Main applications comprise the generation of rock catalogs and synthetic production logs to assist in history matching.
Possible Alternatives for Gas-Charged Accumulators in Deep Waters
Authors: Amani M. , Rajabi M. Mir , Juvkam-Wold H. C. , Schubert J. J. 
Published: December 2007

Abstract
Gas Charged Accumulators are widely used in Drilling operations. These accumulators are not efficient at all in Deep waters, and there are not many alternatives for them. This paper looks into possible alternatives for Gas Charged Accumulators in Deep Waters.
Supplying enough volume of pressurized hydraulic fluid to operate the BOPs for emergency situations is essential for Deep Water Drilling. This requires storing the pressurized hydraulic fluid in accumulators. A problem may arise when the wellhead is at water depth of more than 3500 ft. In deep water drilling, the accumulators are placed on the subsea BOP stack to reduce hydraulic response times and provide a hydraulic power supply in case of interruption of surface communication. Hydraulic fluid capacity of an accumulator may drop to 15% of its capacity on the surface and even less, depending on the water depth. The reason for this is that the nitrogen gas does not behave like an ideal gas as we go to very deep water, due to high hydrostatic pressure at that water depth.
The possibility of the use of springs and heavy weights as possible replacements for nitrogen in the structure of accumulators will be discussed in this paper. High hydrostatic pressure of deepwater will not affect the functionality of these mechanical accumulators.
Transferring bank of accumulators to the surface and connecting them to the BOP with properly sized and rigid pipes can decrease response time to an acceptable level to satisfy regulations and standards. This idea can be considered as an alternative solution too.
We have to include the hydrostatic pressure of water in the usable fluid calculation. A low pressure tank located on the sea-floor can dismiss the negative effect of high hydrostatic pressure of seawater. This alternative idea is also discussed.
Using a column of high density fluid as the accumulator system is another alternative method that is presented in this paper and should be investigated further for such application.
Case Study: The Application of Inflow Control Devices in the Troll Oil Field
Authors: Henriksen K. H. , Gule E. I. , Augustine J. 
Published: December 2007

Abstract
This paper describes the application of Sand Control Screens coupled with Inflow Control Devices (ICDs) in the Troll Oil sub sea field development. Technical and functional description, qualification, computer modeling and production experience verifies that completions with ICDs yield higher volumetric recovery of oil from each well compared with more conventional sand control completion methods. Improved sand control results from the screen systems inflow distribution functionality.
Advanced Completion Technology Creates a New Reality for Common Oilfield Myths
Authors: Augustine J. , Ratterman E. 
Published: December 2007

Abstract
Several myths have historically permeated the oil industry. These myths typically included: "I can't gain incremental production from a lateral exceeding 1500 ft", "I have to produce my well at the critical coning rate to prevent early water production", and "I have to gravel pack my well to achieve sand control and completion longevity". These myths are being conquered with the generational development and implementation of Inflow Control Technology that allows the wellbore to access and produce larger reserve volumes while eliminating the onset of early water production and/or premature gas breakthrough. Inflow Control Technology enables the prevention of water/gas breakthrough by passively controlling the inflow profile along the length of a well. An increased understanding of wellbore and reservoir fluid dynamics has been achieved through the continued research and application of this technology. To address the diversity of reservoir conditions, this understanding has spawned the integration of state of the art completion and inflow control technology to achieve well specific solutions. Optimum completion solutions should be designed to address the reservoir characteristics. Today, the industry has delivered sand control completions in lateral lengths exceeding 11,000 ft, eliminated water breakthrough in naturally fractured carbonate formations, and provided sand control without gravel packing in formations that would have otherwise required a gravel media. This paper discusses the origin of the historical myths and the case histories leading to the obsolescence of these myths. The global applications reviewed include completion installations in the UK and Norwegian North Sea Sectors, and Saudi Arabia.
Reducing Uncertainty of Reserves Estimates Using Inversion of Time-Lapse Logging Data
Authors: Frenkel M. A. 
Published: December 2007

AbstractThe estimation of hydrocarbon reserves heavily depends on the accuracy of resistivity data and the reliability of their interpretation. To optimize data information extraction from acquired modern array resistivity logs, integrated inversion- based interpretation techniques are required. However, the direct application of an inversion method may provide an incorrect equivalent solution, resulting in erroneous hydrocarbon estimates.To solve the equivalency problem, we have developed a new method that reconstructs the formation model in steps using inversion of time-lapse Logging-While-Drilling (LWD) and Wireline (WL) measurements. The main steps are: Estimate resistivities of invaded and uncontaminated zones using LWD data focusing or inversion.Re-estimate resistivity of the invaded zone using WL logs, array data focusing or inversion.Estimate depth of invasion using WL data inversion and the results of the steps above.Re-estimate the model parameters using WL data inversion and the results of the steps above.Estimate parameters of a complex invasion radial profile using WL data inversion.To establish the effectiveness of the method, we tested it on a synthetic example that was constructed using LWD and WL logs acquired in a well from the South China Sea. This field data was also used for our case study.The conclusion is that the suggested method provides a framework for effective integration of time-lapse logging measurements to increase accuracy of formation evaluation.
Diagnosis of Reservoir Behavior From Measured Pressure/Rate Data
Authors: Kabir C. S. , Izgec B. 
Published: December 2007

Abstract
This paper presents a simple diagnostic tool to identify reservoir flow behavior from a Cartesian pressure/rate graph. Some of the benefits of the proposed tool are its simplicity without requiring any calculations, leading to understanding of reservoir compartmentalization and application of an appropriate material-balance technique.
Data diagnosis entails graphing pressure with rate and discerning trends; positive slope signifies the pseudosteady-state (PSS) flow period, whereas the negative slope implies infinite-acting (IA) flow. Constant-rate production exhibits infinite slope whereas constant-pressure production produces zero slope. Mathematical justifications for these diagnostic signatures are presented. During PSS flow, wells belonging to the same container will exhibit the same slope.
Differences in slope are an indication of reservoir compartmentalization, lateral or vertical. Equally important we provide mathematical proof of why different wells in a multiwell reservoir system should have the same slope. Field examples from multiple gas and gas/condensate systems show how the proposed tool works in practice.
Preventing Naphthenate Stabilised Emulsions and Naphthenate Deposits on Fields Producing Acidic Crude Oils
Authors: Hurtevent C. , Ubbels S. 
Published: December 2007

Abstract
Naphthenic acids in a crude from field A in West Africa in combination with high pH connate waters cause severe problems during the separation of oil and water. The neutralization products of those acids with basic components in the water tend to form very stable water-in-oil emulsions and insoluble sticky naphthenate sludge. These phenomena considerably hamper oil production and result in high treatment costs using acetic acid.
This paper discusses the ways problems were prevented during a large field trial with a combined demulsifier/naphthenate inhibitor based on a physical and chemical approach. Innovative technology in surface-active chemistry has demonstrated an effective way to reduce or eliminate the problems described.
In addition, lab tests were performed on an instrumented bottle test that enables the different phases of decantation (Coalescence, sedimentation, dense emulsion) to be measured. Two conventional demulsifiers used in the field were tested and compared to this new combined demulsifier/naphthenate inhibitor. The new chemical prevented the formation of dense emulsion and resulted in better water quality.
Further experiments demonstrating the unique challenges associated with naphthenates in different fields around the world are also presented.
Selective Removal of Water From Supercritical Natural Gas
Authors: Karimi A. , Abdi M. A 
Published: December 2007

Abstract
The demand for natural gas has pushed energy industries toward the discovery of remote offshore reservoirs. Consequently, new technologies have to be developed to efficiently produce and transport natural gas to consumption centers. Common design challenges in all gas processing methods for offshore applications are the compactness and reliability of process equipment. Water vapour is the most common impurity in natural gas mixtures. At very high gas pressures within the transportation systems hydrate can easily form even at relatively high temperatures. Gas dehydration or hydrate inhibition systems for offshore gas production/processing facilities should meet these requirements. It should also be noted that at certain pressure and composition conditions, the presence of heavy hydrocarbons (C2+) in natural gas increases pipeline flow capacity and improves compression efficiencies. Therefore, the development of a compact high pressure system capable of selectively removing water from high pressure natural gas streams without affecting the hydrocarbon content will be needed for especial applications and therefore it will be addressed in this paper. Most hydrate inhibition/water removal systems can only work below certain pressure conditions, are relatively large, and not selective towards water. Therefore, some hydrocarbon condensate is also removed during water dew pointing. The developed technique proposed in this study can be customized for the emerging marine transportation of gas in CNG form where the removal of heavier hydrocarbons might not be necessary and will be equally suitable for any other offshore/onshore natural gas production and processing including subsea production of oil and gas. This paper concentrates on the development of simulation techniques needed to accurately estimate dehydration efficiency to control hydrate in a supercritical flow using supersonic nozzles.
A simulation model linked to a thermodynamic property generator is needed to predict the water removal efficiency under various flow conditions. The computer simulation results for water removal from a typical offshore natural gas stream under various conditions will be presented and compared with conventional techniques. Intensive water dew points down to about -50 to – 60 °C can be achieved without any cryogenic cooling or use of solid adsorption techniques.
Estimating Percentage of Fracture Fairways Detectible by Seismic Data—Case Studies From Oman
Authors: Ozkaya Sait Ismail , Richard Pascal , Mueller Guy 
Published: December 2007

Abstract
This paper discusses the detection of fluid conductive fracture fairways using seismic data calibrated with BHI or dynamic data. Fault-related fractures display a high degree of clustering at several scales. Fracture cluster within fracture corridors and fracture corridors are clustered within fracture fairways, which are overall equivalent to fault zones.
We compared the location and spacing of fracture fairways from image logs with seismic faults and lineaments and estimated the percentage of fracture fairways that can be detected by seismic attribute maps. Correlation with flow profiles, lost circulation and water breakthrough and productivity index was necessary to determine fraction of fluid conductive seismic faults and fracture corridors from borehole images. The results showed seismic fault maps from one of the two fields detected more than 90 percent of all fracture fairways. The fault map could be effectively used for well planning and simulation and in combination with fracture corridor clustering, density and transmissivity data from borehole image logs and pressure transient analysis. Seismic maps from the other field could detect only half of the fracture fairways and indirect indicators from dynamic data had to be used to identify and map fracture fairways.
Studying the Scaling Mechanism of Low-Permeability Reservoirs Using Visual Real-Sand Micromodel
Authors: Xiaojuan Ren , Pingchang Wu , Zhihao Qu , Chengen Shi 
Published: December 2007

Abstract
Chang 3 reservoir in Hua 152 block is located in the Ordos basin, China. The average permeability and porosity is 3.17mD and 14.9%. There exists serious scaling at the oil layer near to bottom hole because of high salinity formation water and incompatible injection water. The scaling process and mechanisms in the layers has been researched by means of a visual real-sand micro-model. The results have shown that: 1) The permeability of the oil layer will reduce by 40% when formation water contacts with injection water twice times at the same place; 2) It is very easy for scaling molecules to crystallize from water phase and scale particles are very small because the pores and throats of the formation rock contain a lot of fine clay and impurity; 3) The scale accumulates in pores and looks like "chicken roost"; 4) The scale inhibitors can reduce scaling, but the higher concentration of scale inhibitors is needed. Scaling in low permeability reservoirs may significantly reduce rock permeability thus affecting the production of oil well. The visual real-sand micro-model is a good method to use in research of scaling mechanisms because of its visualization, using actual rock and ease of construction.
Field Experiences in the Application of an Inhibitor/Additive Interaction Package to Extend an Inhibitor Squeeze Life
Authors: Chen P. , Hagen T. , Montgomerie H. , Berge T. , Haaland T. , Matheson R. , Sæten J. O. , Vikane O. , Børeng R. , Bjørnestad E. Ø. , Asheim T. I. 
Published: December 2007

Abstract
Since the middle 1980s, seawater breakthrough has been observed for a number of wells in a major offshore Field operated by Statoil. This Field has also several tie-ins. Both sulphate and carbonate scale deposition has been identified in the near well bore area and tubing. Inhibitor squeeze treatments were regularly carried out to prevent wells from damages due to scale precipitation. The conventional phosphonate scale inhibitor (DETA-phosphonate) was often used. Some of the sandstone formations in the oil field are relatively "clean" with very little amount of clay materials i.e. Etive and Tarbert formation. As a result, a relatively short inhibitor squeeze life was seen in these formations after the squeeze treatments with a phosphonate scale inhibitor. Other reservoirs had acceptable squeeze life, but due to environmental requirements a wide set of inhibitors was studied.
In order to reduce the well intervention frequency and extend an inhibitor squeeze life, a method involving a polymer interaction between a polymer scale inhibitor and polymer additive has been developed. In addition to the enhanced adsorption; attributed by the surface charge modification by the adsorption of the positively charged polymer additive on the sandstone surface, the interactions between polymer inhibitor and additive further increase the inhibitor retention in the formation. This polymer interaction approach is different from a conventional precipitation squeeze where calcium chloride was used. Also, unlike the conventional precipitation squeeze, the polymer additive can be pre-injected and rapidly adsorbed onto a rock surface. The subsequently injected inhibitor will react with the additive on the rock surfaces, resulting in a precipitation on a rock surface. This avoids the bulk precipitations where a permeability reduction was often caused by a conventional precipitation squeeze. During the production, the precipitated polymer inhibitor was released through a hydrolysis process.
This paper presents a detailed method and field results based on the treatments using the polymer inhibitor and additive package in the oil field. The application of polymer interaction package significantly improved the inhibitor squeeze life. Satisfactory results have been achieved from the field trials. The unique polymer reaction package satisfies the stringent Norwegian environmental regulations of low toxicity, high biodegradation and low bioaccumulation.
Design of Low-Sulfate Seawater Injection Based Upon Kinetic Limits
Authors: McElhiney J. E. , Tomson M. B. , Kan A. T. 
Published: December 2007

Abstract
Reliance on low sulphate seawater as sole protection against sulphate scale may be discomforting to some operators when such expensive subsea wells are at stake. Normal methods such as bullheading squeeze chemicals are nearly impossible to implement due to the long and sometimes multiple flow lines connecting injection wells. Subsea intervention to place squeeze inhibitors is prohibitively expensive due to the requirement of utilizing a service boat over the well for many days.1 Calculations of scaling index from formation and injected seawater mixtures are routinely based upon the thermodynamics of the mixed brines. Although some mixing does occur in the interwell distance, the most vigorous mixing occurs in the vicinity of the production wellbore where water from multiple layers and streamlines impinge. These near wellbore mixtures have short residence times before being produced therefore reaction kinetics must be considered, and it is not clear how low the sulphate concentration in injected water needs to be to delay scaling downhole. This work offers a fresh look at this scaling problem by examining the kinetics of the mixed brines. Using data from existing field projects that currently inject desulphated seawater, the induction times required for non-scaling fluid transit up production wellbores are chosen, and the sulphate concentrations necessary to provide these induction times are computed from a software program.2 The software algorithms are based on a broad, robust database of barite kinetics that span large variations in sulphate and barium concentrations, temperatures and salinities.3 This protocol is compared to scaling index results computed from a thermodynamic approach at both bottomhole and wellhead conditions. A tandem role in which inhibitors can be utilized in conjunction with low sulphate seawater is described.