bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Experience From Smart Wells in the Oseberg Field
Authors: Erlandsen Sigurd M. 
Published: December 2007

Abstract
The Oseberg Field is located offshore Norway 140 km Northwest of Bergen at approximately 100m waterdepth. Including the recently installed Oseberg D gas platform, the field is developed with four offshore installations. The expected reserves estimate is 336 MSm3 of which 266 MSm3 has been produced by January 2000. Pressure maintenance is implemented by re-injection of associated gas and import of gas from the nearby Troll Field. In addition water injection takes place in some parts of the field.
Oseberg is by May 2000 producing approximately 46000 Sm3/d (290000 stb/d) from 42 production wells. Plateau oil production of 81000 Sm3/d (510000 stb/d) ended in 1997. The initial 200m oil column has been reduced to an oil rim of 20-40m as more than 75 percent of the reserves have been produced. Most producers have experienced gas break through and oil production is now limited by gas handling capacity.
The use of smart wells enables remote control of zones with excessive gas production. In the Oseberg Field, such completions have so far been installed in four wells. In the first well one ‘smart’ completion was installed in combination with mechanical sliding sleeves in two other zones. The primary objective was to verify the robustness of the equipment at downhole conditions of the Oseberg field. In the second well four zones with this completion was installed in a channel sand deposit. Rapid gas break through at the heel of the horizontal section was choked remotely, resulting in a reduced GOR and improved oil production rate. The third well with four zones was installed in a more homogenous formation. Communication was lost with three of the four zones after 40 days production. Production from the fourth well commenced in august 1999. Technical operations of the three zones were ok, but the well was experiencing production problems in the beginning due to poor pressure support and lifting problems.
Major Advancements in True Real-Time Hydraulics
Authors: Zamora M. , Roy S. , Caicedo H. Y. , Froitland T. S. , Ting S. -T. 
Published: December 2007

Abstract
Deepwater, HTHP, and narrow pressure-margin wells depend on accurate, real-time knowledge of downhole hydraulics in order to achieve their objectives safely and economically. Pressure-while-drilling (PWD) can satisfy many of the needs. However, PWD measurements are sometimes not available during certain critical operations, are restricted to the tool location, and are unable to provide the "what-should-be" scenario needed for informed decisions. These "knowledge gaps" can be filled by a newly developed wellsite computer system (WCS) designed to model downhole hydraulics behavior from surface drilling data in true real time.
The WCS has been used successfully on nine exploratory wells in the Gulf of Mexico and the North Sea, including eight drilled with narrow operating windows and four drilled in deepwater. Calculated ECDs typically were within 0.1 ppg of PWD values; and the system substituted well for PWD when tools were unavailable, inoperable, or not transmitting data to surface in real time. Also, the WCS helped guide several successful casing and liner jobs run in low-fracture-gradient environments. With no PWD tool installed, the WCS was uniquely available to provide the instant feedback needed by drillers to prevent problems before they occurred.
Relevant measured and interpreted information is graphically displayed on the WCS screen during drilling and tripping operations. Simultaneously, key parameters can be displayed at the driller’s station as if they were measured values. Calculated downhole ESD, ECD, hole-cleaning efficiency, temperature, and other hydraulics-related profiles are based on comprehensive models proven successful in a wide range of drilling applications. Considerations for transient behavior have been added in order to adapt and update the models for use in real-time environments.
Major advancements introduced during the WCS development and refined by its subsequent use are the subject of this paper. This is accomplished within the framework of hardware and software descriptions, basic modeling concepts, and multiple examples of drilling and tripping data generated during field applications. Also included is a discussion of enhancements that could be realized by improved modeling, better sensors, and expansion into related disciplines.
Reservoir Characterization Using 3D AVO and 3D Net Sand Prediction
Authors: Skidmore C. M. 
Published: December 2007

Abstract
The major issues that face us today revolve around economics. Finding hydrocarbons has been made easier with 3D data, but the proper delineation and quality of the deposit still often eludes us. Application of a series of amplitude attributes indicates that applying one technology, such as Amplitude Strength, is not enough. The issues that impact the economics of a reservoir are varied and complex, therefore multiple techniques must be used to address them.
Application of seismic attributes to three areas of the Gulf of Mexico, in a consistent manner, demonstrates how effective technology can be when applied properly. The three areas examined all had similar Amplitude Strength, but drilling results in the area produced varied results. The Mississippi Canyon 486 field was first examined because of the strong variation in reservoir thickness. The sixteen wells drilled in the field have gross thickness variations from 23 to 160 feet, and net thickness variations from 0 to 160 feet. Amplitude maps over the field do not indicate this complexity, and agree very poorly with the drill results. Advances in technology, mainly in the areas of AVO, Thickness, and Rock Property estimation, offer a much clearer picture of the reservoir size. Similar technology applied to a second area correctly predicted the poor outcome of an initial well and indicated the presence of cleaner and thicker reservoir in the immediate area. A sidetrack was drilled and an economic discovery was announced. The third location also has a strong amplitude anomaly similar to the other two. The AVO signature suggests the presence of hydrocarbons, but thickness predictions indicate very low net/gross sand ratios in the reservoir. The well drilled into the anomaly was plugged and abandoned.
A Multiresolution Approach to Reservoir Parameter Estimation Using Wavelet Analysis
Authors: Lu Pengbo , Horne Roland N. 
Published: December 2007

AbstractIn this paper, a new multiresolution approach is proposed for reservoir parameter estimation, i.e., to estimate the spatial distribution of the reservoir properties by proper integration of all types of data available (either static or dynamic). We considered the integration of production history data, seismic data and well test data in this work.One of the key issues in parameter estimation is to develop an efficient and reliable nonlinear regression procedure. We adapted wavelet analysis to describe the distribution of sensitivity coefficients, since wavelet analysis is a powerful tool in multiresolution analysis and is widely used in signal and image processing. Wavelet analysis can compress the parameter space, stabilize the algorithm and avoid local minima. This new approach also improves the computational efficiency significantly by varying the resolution of the estimation at different regression stages.Wavelet analysis also has the capability to integrate different types of data efficiently, using different levels of wavelets to incorporate different data types. We can account explicitly for the resolving power of different data and estimate reservoir properties with nonuniform resolution.We have applied the procedure to multiphase reservoir examples that demonstrate the reliability and flexibility of the approach. We also gained very good convergence and excellent computational efficiency compared to conventional methods. The most important conclusion of this paper is that wavelet analysis is a very useful tool for reservoir parameter estimation and can speed up the computation and improve the performance. The nonlinear regression procedure integrating wavelet analysis has substantial advantages over the conventional algorithms.
Visualisation of Oil Recovery by Water Alternating Gas (WAG) Injection Using High Pressure Micromodels - Water-Wet System
Authors: Sohrabi M. , Henderson G. D. , Tehrani D. H. , Danesh A. 
Published: December 2007

Abstract
The use of WAG (water alternating gas) injection can potentially lead to improved oil recovery compared to injection of either gas or water alone, however the physical process is not well understood. Using high pressure glass micromodels, a series of WAG tests have been conducted using equilibrated fluids, with high quality images of the oil recovery processes operating during alternate WAG cycles being recorded. The tests were conducted using both water-wet and oil-wet micromodels. In this paper results of a typical water-wet test is presented (results of the oil-wet and mixed wet tests will be presented in a subsequent paper).
Water-wet micromodels were initially fully saturated with water and then displaced with oil to establish the connate water saturation. The micromodels were then flooded with water to observe the process of establishing the waterflood residual oil saturation (Sorw). Alternate cycles of gas and water injection were then conducted to observe three-phase flow and its associated oil recovery. The experiments were performed within the capillary dominated flow regime.
The results highlighted the importance of corner filament flow of water in the recovery process, with the initial waterflood residual oil saturation being trapped mainly in the centre of the majority of pore space surrounded by layers of water, and not in only large pores. The successive WAG cycles redistributed the oil in a way which resulted in improved oil recovery, hence, the oil which otherwise would not have been mobile under either gas or water injection alone was mobilised and produced.
It was identified that a limited number of WAG cycles were required to approach maximum oil recovery, after which additional recovery was minimal. All recovery processes were filmed and electronically stored using high resolution imaging, with oil recovery at the end of each flooding cycle being measured using image analysis techniques.
State-of-the-Art Interventionless Completion Technology Provides Key to Greater Cost Reduction and Completion Efficiency
Authors: Simonds Randy , Navarro Juan , Skinner Neal , Schneller Tricia 
Published: December 2007

Abstract
A new system for the remote, interventionless actuation of downhole completion equipment has been developed to support industry needs to lower costs and preserve asset values. The traditional methods for setting a production packer employ coiled tubing or slickline to run a tubing plug. The new system provides a safe, reliable and more cost effective alternative to traditional intervention because it simply transmits acoustic pulses through the contents of tubulars to actuate one or more completion or service tools remotely in any desired sequence.
The system not only decreases the time to set the packer but also extends the envelope for application to deep, extended-reach offshore environments. Since the system eliminates the need to circulate a ball downhole to set service tools during sand control operations, the operator can maintain constant hydrostatic pressure on the formation. This capability decreases completion time, intervention risk, the possibility of formation collapse against the completion string, the possibility of losing the filter cake placed against the formation, and fluid loss to the formation.
To achieve the goals required for this system, three project targets were addressed: a reliable means of wireless communication, a surface control system, and a downhole power unit for completion device actuation. The design and capabilities of the new surface-operated, non-intervention completion system will improve completion economics.
Design and Installation of a Sand Separation and Handling System for a Gulf of Mexico Oil Production Facility
Authors: Rawlins C. H. , Staten S. E. , Wang I. I. 
Published: December 2007

Abstract
A comprehensive system for the separation and handling of sand from produced fluids was designed and installed in a Chevron facility in the Gulf of Mexico. This system involves two multicone desander systems, one on the water outlet and one on the oil outlet of an LP separator, to provide separation of sand from produced fluids. The separated solids are collected, dewatered, and transported to a unique, simple solids handling system designed for complete fluid containment and safe handling. The focus of this paper is to present the design of the separation and handling system, and discuss the various challenges encountered during and after commissioning. The topics covered include desander operation (pressure drop and separation), slurry discharge from the desander, dewatering of slurry, recycling of fluids, and transport of the collected solids from platform to shore.
Artificial Lift for Slim Holes
Authors: Lea J. F. , Cox J. C. , Adisoemarta P. S. , Nickens H. V. 
Published: December 2007

AbstractLiquid removal from gas wells is needed as reservoir pressure declines resulting in lower gas flow rates. As liquids accumulate in the wellbore, the hydrostatic pressure due to the liquid column exerts a backpressure on the producing sand face resulting in lower production rates. As additional liquids enter the wellbore, the well will cease to flow. By removing these liquids, gas production is maintained. Since various artificial lift techniques are used to produce these liquids, it is important that the lifting method be compatible with the size of the completions. The purpose of the paper is to discuss which options are available to lift liquids from slim-hole gas wells.
Evaluation of Frac-and-Pack Completions in the Eugene Island
Authors: Fan Y. , Markitell B. N. , Marple B. D. , Valkó P. P. 
Published: December 2007

Abstract
This paper presents a systematic evaluation of frac&pack completions conducted in the Eugene Island region of the Gulf of Mexico. Reservoir, treatment and production data are analyzed from a unified viewpoint. First a completion design strategy is described which is centered around the dual goals of optimal stimulation and sufficient sand control. Then a method is presented to evaluate the technical success of the completion using 3-D reservoir/fracture simulators and the recently developed Slopes Analysis method. Finally, a simple but practical frac&pack treatment design and optimization procedure is presented for improving the performance of frac&pack completions. An example of frac&pack treatment design using the new design philosophy is provided in details showing how to achieve the stimulation goals in a theoretically optimum manner and why often the actual treatment has to depart from the theoretical optimum.
Optimization of Hydraulic Fracturing in a Deep, Multilayered, Gas-Condensate Reservoir
Authors: Langedijk R. A. , Al-Naabi S. , Al-Lawati H. , Pongratz Oman, R. , Elia M. P. , Abdulrab T. 
Published: December 2007

Abstract
Two deep, gas condensate reservoirs are under development in Oman to supply a peak capacity of 40 million m3/d gas for Liquefied Natural Gas (LNG) export and domestic customers. To date (May 2000) 37 multiply-fractured development wells, with a total of 106 hydraulic fracture treatments have been completed in the multi-layered, heterogeneous Barik and Saih Rawl fields.
A continuous optimization process was in place from the beginning to capture all aspects of the project’s learning and reduce development cost. The frac design changes over time as a result of this process will be discussed. Initial well capacity of the wells cleaned up and tested to date is 20% higher than planned, offering considerable project savings.
This paper will describe the way in which the significant challenges in fracturing these deep, multi-layered gas-condensate reservoirs were met.
Difficulties in interpreting and analyzing FETs (Fluid Efficiency Tests) caused by varying stress contrasts in the different layers will be discussed. It will be shown that masking early data of the pressure decline after shutdown in the minifrac can result in misinterpretation of leakoff parameters. Well tests performed at regular intervals gave a better understanding of the optimized relationship between length, width, and height, which in turn led to a revised fracturing design. Perforating strategies influencing the placement of individual fracturing treatments, in particular affecting fracture connected height, will be addressed. Modeling reservoir characteristic has presented significant hurdles with existing fracture simulators, primarily caused by the amount of detail required to accurately predict both the fracturing and productivity behavior in the heterogeneous Barik and Saih Rawl fields.
Mechanistic Model for Upward Two-Phase Flow in Annuli
Authors: Lage Antonio C. V. M. , Time Rune W. 
Published: December 2007

Abstract
A mechanistic model is formulated to predict the mixture behavior for upward two-phase flow in concentric annulus. The model is composed of a procedure for flow pattern prediction and a set of independent mechanistic models for calculating gas fraction and pressure drop in bubble, dispersed bubble, slug and annular flow.
Small-scale experimental data from the literature validate the predictions of the model. A full-scale experimental investigation is also executed to complete the evaluation. The experiments are performed in a 1278 m vertical well in the Petrobras research facility in Taquipe, Brazil, with an 88.9 mm x 159.4 mm (3.5 in. x 6.276 in.) annulus. Test matrix covered the whole range of possible combinations of liquid and gas injection rates for an underbalanced drilling operation in a similar geometry. The overall model performance is in good agreement with the experimental data.
Dynamic Reservoir Characterization at Central Vacuum Unit
Authors: Wehner Scott C. , Raines Michael A. , Davis Thomas L. , Benson Robert D. 
Published: December 2007

Abstract
Multicomponent, time-lapse seismology has great potential for monitoring production processes in reservoirs. The main reason is simply the presence of fluid-filled fractures. Shear waves (s-waves) are much more sensitive than compressional waves (p-waves) to the presence of fractures or microfractures and the fluid content within the fracture network. Fractures introduce seismic anisotropy into a reservoir, causing two shear modes (S1 and S2) to propagate with different velocities and therefore different arrival times. This phenomenon is referred to as s-wave splitting or birefringence, and is critical for estimating fracture density (see Martin and Davis, 1987).
At Central Vacuum Unit (CVU), s-wave splitting is developing as an important key to monitoring production processes associated with carbon dioxide (CO2) flooding. Fluid property changes associated with CO2 flooding produce changes in the velocities of the split s-waves passing through the reservoir interval. Fluid properties change in response to CO2 and oil becoming a miscible phase in the presence of in-situ fluids. S-wave splitting can also be used to identify areas of anomalous reservoir pressure. S-wave splitting and velocities are extremely sensitive to the local stress field because all rocks, especially carbonates, contain incipient networks of microfractures at a state of near-criticality (Zatsepin and Crampin, 1997).
S-wave splitting can assist in separating effective stress changes associated with abnormal fluid pressures from fluid property change. This conclusion is inferred by results of the CVU study. During the first phase, Phase-I of this study, a prominent s-wave splitting anomaly was detected to the south of a cyclic CO2 injection well (CVU 97). It is believed that this anomaly corresponded to the tertiary flood bank that developed south of this temporary injection well (Figure 1a). Noticeable in the periphery to this anomaly are anisotropy anomalies of opposite sign related to offset wells that were used to contain the CO2 bank through water injection. The sign change of s-wave anisotropy occurs because the relative velocities of the split s-waves reverse. In the case of the miscible CO2-oil bank, the S2 velocity increased and S1 decreased, whereas, in the case of water injection, the effective stress causes S2 to decrease and S1 to increase. Similar effects were observed during the second phase, Phase-II of the monitoring study (Figure 1b). These results imply that s-wave anisotropy can be used to monitor secondary (water flooding) as well as tertiary (CO2) methods in a spatial context beyond the wellbore. This dynamic reservoir characterization could provide the industry with the ability to be more proactive than reactive in the management of reservoirs.
Scale Effects on the Application of Saturation-height Functions to Reservoir Petrofacies Units
Authors: Worthington Paul F 
Published: December 2007

Abstract
An internally self-consistent reservoir model has been constructed in order to investigate the effects of scale on the mathematical form and application of four saturation-height functions and thence on the resulting distribution of reservoir fluid saturations. The deterministic treatment uses reservoir partitioning into strongly characterised, but uncorrelatable, physically-distinct litho-units, or petrofacies, for purposes of petrophysical interpretation, and a separate, spatially correlatable reservoir zonation for subsequent parameter mapping and volumetric computations.
The relationship of a petrofacies-specific saturation-height function established at the core-to-log scale to that generated at the reservoir zonal scale varies according to the form of function used and the physical character of the particular petrofacies unit. The deterministic application of diverse functions established at the two different scales has allowed the uncertainties introduced through scale transgression to be compared quantitatively in terms of the predicted zonal water saturations, and thence hydrocarbon saturations, delivered for the parameter mapping stage. The most accurate evaluation of water saturation is provided by an extended algorithm that contains bulk volume water as predictand and was established at the reservoir zonal scale, which has to be used in subsequent volumetric applications. In contrast, an exponential form of saturation-height function is the worst performer, regardless of the scale at which it was established.
The significance and variability of this uncertainty have led to the formulation of a structured approach to the optimum deterministic application of saturation-height functions in integrated reservoir description. Through this facility, it is possible to constrain the uncertainty associated with the distribution of hydrocarbon saturation at the mapping and volumetric stages.