bluuebunny/crossref_metadata_2025_split huggingface dataset:
History Matching Considerations of an Analogue Reservoir Model (ARM)
Authors: Montague E. T. , Sherlock D. H. , Santoso E. 
Published: December 2007

AbstractThis paper describes a research program at the Australian Resources Research Centre (ARRC) to establish and use an analogue model to gain insight into issues of uncertainty in numerical reservoir simulation. Reported in this paper are the initial findings from history matching the production response of an Analogue Reservoir Model (ARM) and its numerical representation in a finite difference simulation model. The ARM is a large-scale physical model comprising two intersecting synthetic sandstone channels encased within an impermeable acrylic matrix. The initially oil-saturated model was waterflooded via the upper channel and the injected water was dyed blue to allow the displacement process to be recorded on video. Production rates, pressures, water cuts, etc were recorded and used to history match the reservoir simulation model.The simulation model was built using Roxar's Nextwell software, and populated with the rock and fluid properties of the ARM. The initial history matching attempt did not yield a good match. The model was unable to match the preferential flow of water along the lower channel. It was discovered later that the lower channel had become inadvertently fractured during fabrication of the model. Although incorporating the fracture system into the simulation model significantly improved the quality of the history match, the character of the water cut development was dependant upon the relative permeability curve used. It has been well documented that different relative permeability curves are used to model fluid flow through porous media as opposed to fracture and fracture-matrix flow This ARM provides a unique opportunity to test the applicability of published fracture relative permeability models by using these in history matching the production response between the reservoir simulation model and the physical model.
Modeling of Coupled Reservoir and Multifractured Horizontal Well Flow Dynamics
Authors: Vicente R. , Ertekin T. 
Published: December 2007

Abstract
A fully implicit numerical model coupling reservoir and multifractured horizontal well flow dynamics has been developed to investigate the flow behavior and predict the productivity of such systems. The simulator solves simultaneously for pressure distribution within the reservoir and horizontal well domains, while taking into account the friction losses along the wellbore for laminar and turbulent flow conditions. Fractures with distinct properties are placed perpendicular to the wellbore axis and can intersect the well at arbitrary locations. The model is unconditionally stable and can be used to analyze the early transient period as well pseudo- and steady-state conditions.
The use of multifractured horizontal wells has been gaining popularity in tight reservoir systems; however, the existing design protocols do not consider wellbore hydraulics that can have a governing role in the performance of the system. The appropriate design of a multifractured well has a definite impact on its performance. The numerical model presented in this paper can be utilized as a design tool towards the optimization of the number, position and penetration lengths of the fractures connected to a horizontal well.
The calculated influx and pressure distributions along the wellbore show that solutions can deviate dramatically from the actual behavior if infinite conductivity idealization is used to represent flow dynamics in the horizontal well, and this discrepancy becomes more pronounced with an increase in reservoir permeability. Parametric studies are conducted to evaluate the influence of the number of the fractures in the flow behavior and productivity of the system. The observations and analyses presented in this paper will provide the much needed guidance to engineers who face the daunting task of designing a cost-effective optimum fracturing scheme in horizontal wells completed in formations with different flow characteristics.
A New Asymmetrical Array Induction Logging Tool
Authors: Xiao J. , Buchanan J. , Bittar M. , Davis E. , Sanmartin L. , Hu G. , Zannoni S. , Morys M. , Liu W. 
Published: December 2007

Abstract
While array induction tools are fast approaching the 20 year mark for commercial service, a few nagging questions persist in the minds of induction tool designers. These questions relate to some of the compromises in hardware design and data processing that were necessary in the previous generation of tools. These compromises can give rise to various uncertainties in the data that ultimately degrade log responses. A new array induction tool has been designed that addresses these issues.
All array induction tools promise radial resistivity curves with focal depths ranging from 10 inches up to 120 inches. However, few users are familiar with the potential uncertainty that stems from the design of the fundamental sub-arrays. In the new tool, dedicated sub-arrays are closely associated with each computed radial curve. By doing so, the new tool produces radial curves with a minimum of extrapolation. The payoff for the user is more accurate radial resistivity curves and a higher fidelity description of the formation and the near wellbore environment.
This paper also describes the progress made in calibration methods and correction for thermal effects. While these subjects typically receive little attention in the literature, they are critical to the accuracy and repeatability of array induction measurements. The rigorous calibration method described in this paper assures accuracy across a large population of tools and also insures insensitivity to the calibration environment. The complexity and magnitude of thermal effects on array induction tools is examined alongside a robust, thermodynamic method for correcting them.
Finally, several other methodologies are highlighted. A skin effect correction method uses only the in-phase signal measurements and corrects for the skin effect in the aspect of the apparent conductivity value and in the aspect of geometric factors as well. A real time borehole correction method computes the borehole effect with adaptively inverted borehole size, tool eccentricity, and mud resistivity. A new inversion methodology improves the efficiency and stability of the realtime radial inversion.
Treatment of Seawater With Cartridge Filtration—A Field Trial
Authors: Lee J. M. , Frankiewicz T. , Walsh J. 
Published: December 2007

Abstract
In offshore operations, seawater is often injected to maintain reservoir pressure for enhanced oil recovery. A sulfate reducing membrane (SRM) is typically used to reduce the sulfate content in the seawater from 2900 mg/l to less than 50 mg/l to prevent souring of the reservoir by sulfate reducing bacteria and formation of barium and strontium sulfate scale when seawater is mixed with formation water. A two cartridge in series filtration pilot unit installed on a deepwater platform in the Gulf of Mexico has demonstrated that cartridge filtration can be used upstream of the SRM to pretreat seawater to meet the SRM feed seawater specification of SDI&lt;5 and NTU&lt;1. Scanning Electron Microscopy/Energy Dispersive Spectroscopy (SEM/EDS) was used to determine the composition of the material deposited on the surface of a used cartridge filter. From the SEM/EDS results, it was concluded that the filters were blocked predominantly by coccoliths (calcium compounds), diatoms (silicon compounds), iron oxide corrosion products, and broken, crushed marine debris, that formed a fine grained membrane cake on the filters. It was found that a two filter in series configuration is a better seawater filtration system than just using one single filter if seawater with an SDI &lt; 3.5 is required. With the installation of a 50 micron nominal filter upstream of a 10 micron absolute filter, the service life of a 10 micron filter was increased by 20 times.
Snohvit and Beyond—Setting New Standards for Subsea to Shore Developments
Authors: Witting Fredrik 
Published: December 2007

Abstract
This paper discusses the area of long subsea tie-back developments, and what the limiting factors and related technology barriers are related to this area. The paper starts by providing a brief overview of the Snohvit subsea development in the Barents Sea, which holds the current world record in tie-back distance, from an all-subsea development back to shore. On the basis of the technical solutions for the Snohvit development, the paper goes on to discuss what the technical implications would be if the tie-back distance was extended to a level of about three times that of the Snohvit development, thereby making the system able to accommodate ultra-long step-out distances, including even some of the most remote E&P prospects currently known to the industry.
The paper concludes that step-out distances of these magnitudes would be technically feasible, based on use of technology solutions from the Snohvit development and more or less conventional subsea technology building blocks. An important exception from this, however, would relate to the area of providing high levels of subsea electrical power over long distances. For many all-subsea developments with long step-out distances, subsea high voltage power distribution will be required to provide sufficient power to support subsea gas compression schemes. The required power levels and transmission distances far exceed the current capabilities of the industry in this regard. Therefore, the feasibility of such field development concepts will necessitate development and implementation of technological solutions to meet this challenge.
Well Engineers Deserve a Seat at the Exploration Table: The Role of Mechanical Earth Modeling in the Early Exploration Process
Authors: Goodman H. E. 
Published: December 2007

Abstract
Consideration of the full cycle asset development plan from appraisal through abandonment reduces the risk of missed future opportunities caused by well systems design constraints. For example, reservoir pressure depletion and subsidence can impact borehole stability to the extent that complex well designs are necessary to fully exploit the asset. Well placement not only depends on the subsiding reservoir section, but also on the reaction of the overlying geological section that must be drilled through to reach the reservoir. For land-based operations, the consequences of well complexity may be more easily addressed, the downside being a poor estimate of field recovery that can either rob opportunities for outlying prospects or, in the worst case, cause the asset to be uneconomic. For major capital projects (MCPs) such as deepwater subsalt fields, the capital outlays are immense, with single wells costing up to $100,000,000. For these deepwater MCPs, fewer wells are required to produce reliably for longer periods.
The capability to characterize rock mechanical properties from the standard P-wave acoustic datasets, either seismic or openhole log derived, enables well planners to link the Explorationist and Well Engineer's visions using mechanical earth modeling technology. The accurate assessment of formation rheology, or stiffness, and architecture (distribution and structure), allows the asset team to optimize well systems design, considering placement and production management practices over time.
The presentation will introduce acoustics-based rock mechanics concepts, describe the acoustics-based rock property prediction technique, and present field applications that demonstrate the impact of the subsurface model to the corresponding well systems design.
Environmental Challenges of Heavy Crude Oils: Management of Liquid Wastes
Authors: Neff Jerry M. , Hagemann Randi 
Published: December 2007

AbstractLarge volumes of produced water are generated during production of heavy crude oil and large volumes of surface water often are needed to produce, transport, and upgrade heavy crude oils and bitumens. The most important alternatives for managing produced and process waters include volume minimization, underground injection, discharge to surface waters, and beneficial reuse. Produced and process waters often contain high concentrations of inorganic salts, metals, hydrocarbons, and organic acids. They may cause ecological damage if discharged untreated to surface waters or soils. Salts harm terrestrial vegetation and naphthenic acids and polycyclic aromatic hydrocarbons are toxic to aquatic organisms. Most produced water is either reinjected into a non-producing formation or used for enhanced oil recovery (EOR) technologies, such as cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD), or bitumen transport and upgrading by slurry pumping and alkaline extraction. Before use or discharge to surface waters, the produced water must be treated to remove dissolved salts, organic acids, hydrocarbons, and suspended solids. Wastes from cold heavy oil production with sand (CHOPS) usually are pumped to stock tanks where the gas, water, oil, and solids are separated and the produced water is piped to a disposal well. The solids are stored in tailings ponds. Wastes produced during processing oil sands bitumen from surface mining with hot alkaline water also are stored in tailings ponds. Water may be decanted from the tailings ponds and reused or reinjected into a non-producing formation. Tailings ponds containing mature fine tailings may be reclaimed as lake basins. Several new technologies are being developed to remove salts, organic acids, and hydrocarbons, and to break stable heavy oil-water emulsions so that produced and process waters can be reused without damaging production equipment and producing formations or discharged without harming the environment.
Integrating Seismic-Derived Porosity Into a Geocellular Model—A Case Study
Authors: Mercado Gary , Ikawa Hidemasa , Elhami Mohamed , Belgaid Adel 
Published: December 2007

Abstract
The goal of this study was to create a 3D seismic based porosity volume for specific carbonate reservoirs zones and integrate this derived porosity into a geocellular model containing 257 points of well control porosity. The 3D marine OBC seismic data covered a 1500 km2 area of a super-giant Middle East oil field. The Late Cretaceous reservoirs in the field consists of limestone and dolomitic limestone and target zones are subdivided into 3 alternating porous and dense zones. The porous zones range from 30-40 feet thick.
The data was inverted to pseudo acoustic impedance using a well-driven model based technique. Sixty two wells were used to create the initial impedance model for the seismic inversion mainly to provide low frequency trend which tied the log data to the seismic data. A neural network process was applied that utilized the seismic inversion data with several other seismic-derived attributes, in order to maximize the correlation values in reservoir zones and minimized PHIE prediction error in the created porosity volume in time domain.. The seismic based porosity information was depth converted and read into a geocellular model and used as trend data.
Geostatistical methods are commonly used to integrate seismic derived porosity, since it honors well data as well as the degree of correlation between seismic pseudo-porosities and log porosities. This method can create a 3D model that takes advantage of the well log data's fine vertical resolution and the seismic attribute's lateral resolution. The geostatistical method used to achieve this is collocated cokriging. Collocated cokriging can be utilized with two methodologies: kriging (interpolation) and conditional simulation. The first approach is a deterministic method, whereas the latter approach attempts to honor the spatial variability of the conditioning data and also provides multiple realizations.
The lateral distribution of the porosity, controlled by the seismic data in between the wells enable an accurate estimate the inter-well petrophysical properties which had a great impact on the uncertainty in the volumetric calculations of these reservoirs. Validation of this approach was blindly tested by the new drilling locations in the field.
Enhancement of Leakoff-Tests Values in Plastic Clays by Mud Additives— A Case Study in Deepwater Wells in the Krishna Godavari Basin Offshore India
Authors: Singh Raj K. , Holasek Fred R. , Gulati S. C. , Ratan Vijay , Thyagaraju B. A. 
Published: December 2007

Abstract
Common characteristics of deep water wells are narrow separation between pore pressures and fracture gradients along with, comparatively with onland, lower values for the latter. Well designing for such scenario is always been a challenge for drilling engineers. To win over this situation, often-inevitably, wells are designed with multiple casing plans leading to higher cost for already cost intensive deepwater projects. Drilling with manageable losses has been employed as a tool to reach target depths set for sections of the well. Drilling fluid additives are also effectively being used and promoted as LOT enhancers or formation-break-down-pressure improvers based on tests carried out in laboratories.
The paper presents a study of demonstration and evaluation of the performance of a mud additive (sulphonated asphaltic resins) based on extended leak-off-test values.
The paper reports results from an extensive case study carried out in a major ONGC deep water project involving several deep water wells in Krishna-Godavari Basin offshore, India.
The results presented are the demonstration of the role of mud additive in enhancing LOTs in deepwater wells as well as the validation of the technique applied for evaluations as the study incorporates sample and control well strategy for this purpose.
The drilling fluid additive was successfully employed for improving leak-off-test values/break-down-pressure in the deepwater project.
Performance of mud additive for improving LOTs by extended leak-off-test method employing digital data was evaluated and the same may be used for general application.
Underbalanced Drilling in Saudi Arabia-Start Up Experience
Authors: Muqeem M. A. , Al-Jeffre A. M. , Jarrett C. M. , Al-Khanferi N. M. , Killip D. R. , Abdul H. J. 
Published: December 2007

Abstract
This paper describes Saudi Aramco’s initial experience introducing Underbalanced Drilling (UBD) technology in the Ghawar field. The intention was to prove that a step change in performance could be achieved by the application of this technology. Thus the intent was to optimize well design that will result in reduced unit well cost. The reasoning for applying this technology in power water injection wells (PWI) was the low risk involved in drilling these wells. The primary objective of drilling wells underbalanced was to eliminate formation damage and improve injectivity, thereby eliminating the need for acid stimulation. Further, increased rate of penetration (ROP) will result in reduction in drill time and cost. A major campaign was implemented in the Ghawar field to evaluate UBD in Saudi Arabia. Injection rates were dramatically improved and the need for acid stimulation was eliminated. ROP increased significantly when compared to conventional PWI wells. By the time this paper was completed, three oil wells had been drilled underbalanced. The drilling operations and some of the safety issues only will be highlighted. The operations and results are still being evaluated and hopefully will be presented in the near future.
Emerging Petroleum-Oriented Nanotechnologies for Reservoir Engineering
Authors: Evdokimov Igor N. , Eliseev Nikolaj Yu. , Losev Aleksandr P. , Novikov Mikhail A. 
Published: December 2007

Abstract
The paper describes experimental/analytical research aimed at modification of petroleum technologies to "nanotechnologies" by accounting for molecular processes in nanocolloids of native petroleum fluids.
Our results show that in course of traditional technological operations, macroscopic properties of petroleum media (viscosity, density, pour point, etc.) may exhibit abrupt changes caused by currently uncontrolled microscopic phase transitions in nanocolloids. In particular, our experiments provided phase diagrams of petroleum nanocolloids, which show critical parameters, highly unfavorable for industrial processing of petroleum. E.g., petroleum fluids may practically solidify at RT after a short-time residence at the temperature-defined phase boundary of ca. 28–35°C; native crudes of diverse origin exhibit sharp viscosity/density peaking at several composition-defined phase boundaries which are relevant to compatibility problems. Contrary to widespread assumptions, the current properties of petroleum nanocolloids (and, hence, the current properties of petroleum fluids) are not defined solely by current technological parameters. Of equal/decisive importance are the details of a preceding history of reservoir development.
We conclude that proper recovery "nanotechnologies" should be designed and performed with an understanding of importance of the complex nanophase diagrams of petroleum fluids. Such technology should include specifically designed processes (employ specifically selected parameters) to purposely avoid/instigate particular phase transformations in petroleum nanocolloids in order to improve (or, at least, not to ruin) the practically important bulk properties of petroleum. With respect to immediate practical applications, it should be emphasized that the discussed phase diagrams contain only "the most obvious" nanophase boundaries, reflect our current knowledge of structural transformations in petroleum and should be subjected to further investigation.
Transient Fluid and Heat Flow Modeling in Coupled Wellbore/Reservoir Systems
Authors: Izgec B. , Kabir C. S. , Zhu D. , Hasan A. R. 
Published: December 2007

Abstract
This paper presents a transient wellbore simulator coupled with a semianalytic temperature model for computing wellbore-fluid-temperature profile in flowing and shut-in wells. Either an analytic or a numeric reservoir model can be combined with the transient wellbore model for rapid computations of pressure, temperature, and velocity. We verified the model with transient data from multiple gas and oil wells, where both surface and downhole data were available. The accuracy of the heat-transfer calculations improved with a variable-earth-temperature model and a newly developed numerical-differentiation scheme. This approach improved the calculated wellbore fluid-temperature profile, which, in turn, increased the accuracy of pressure calculations, at both bottomhole and wellhead.
The proposed model accurately mimics afterflow during surface shut-in by computing velocity profile at each timestep and its consequent impact on temperature and density profiles in the wellbore. Surrounding formation temperature is updated every timestep to account for changes in heat-transfer rate between the hotter wellbore fluid and the cooler formation. Optional hybrid numerical differentiation routine removes the limitations imposed by the constant relaxation-parameter assumption used in previous analytic-temperature models.