bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gas/Condensate and Oil Well Testing - From the Surface
Authors: Fair Chris , Cook Betsy , Brighton Tom , Redman Michael , Newman Stacy 
Published: December 2007

Abstract
Since Cullender and Smith(1), surface pressures have been used to calculate bottomhole pressures on shallow, dry gas wells. If the original Cullender and Smith equations are modified to account for produced liquids, the correlation may be extended to gas/condensate wells that are single-phase in the well bore. Single-phase liquid wells (water injectors and oil wells above the bubble point) can also yield accurate well test results from the surface. Testing from the surface reduces the cost and eliminates the risk of running tools into well bores. Surface testing also allows the testing of high-pressure/high-temperature wells that cannot be tested with a downhole gauge because of harsh conditions. Thus, to reduce the cost and risk (or when no other option is available), many operators have chosen to run their pressure transient tests from the surface on single-phase wells.
Recently, it has become possible to test most naturally-unloading gas/condensate and oil wells from the surface. This is due to advances in multi-phase wellbore modeling along with improved pressure transducer quality. Of these, the most important advances are the improvements in transducer manufacture and calibration that make it possible for a surface pressure gauge to be effectively isolated from ambient and wellbore thermal transients. Although the technology exists to get representative reservoir data from the surface, testing procedures in multi-phase wells have to take into account the fluid's behavior in the well bore. With this in mind, the purpose of this paper is to propose guidelines for testing multiphase wells from the surface. First, the general framework of the surface-to-bottomhole pressure calculation will be presented. Next, multi-phase wells will be categorized based on the type of fluid and the behavior of the fluid both in the reservoir and in the well bore. This categorization will be the basis for both surface testing candidate selection and recommended test procedures. Afterwards, wellbore phase and temperature modeling will be discussed. Next, instrumentation requirements will be presented. Finally, field data comparing calculated bottomhole pressures from surface gauges to measured bottomhole pressures from downhole gauges (and the subsequent analysis) will be presented for both a gas/condensate and an oil well.
These examples will be used to demonstrate that in order to test a multi-phase well from the surface, a thermally compensated quartz pressure gauge must be used in conjunction with a properly designed and executed test procedure. An explanation will also be provided as to why the best test that can be performed on a well to determine skin, permeability and the size of a reservoir is a constant-choke drawdown.
Managing Turbulent Technology for Exploration and Production Success
Authors: Wye Robin 
Published: December 2007

Abstract
Strategic technology innovation is increasingly being seen as a key value driver for leading companies across many industries - it is no longer sufficient to focus solely on incremental advances in technology, processes, or business models.
From analysis of leading technology innovators, across multiple industries, we have developed a six-part model for management of turbulent technologies (MTT) – those that have the capability to drive a step-change in corporate performance.
We also show evidence that analysts are increasingly looking at technology to deliver the next wave of upstream value creation – making the MTT model highly relevant for shareholders and managers.
We describe key elements of the model, and present examples of effective technology management from inside and outside the upstream industry.
Finally, we highlight the main steps required to develop a model for management of turbulent technology, and conclude that upstream oil and gas companies adopting the MTT model can potentially make significant gains in value and enhance their competitive position.
Pore-Scale Modeling of Three-Phase Flow in Mixed-Wet Systems
Authors: Piri Mohammad , Blunt Martin J. 
Published: December 2007

Abstract
We use a pore-scale network model of three-phase flow to compute relative permeabilities, saturation paths and capillary pressures for a variety of displacement processes. The model is based on a random network of pores and throats with triangular, rectangular and circular cross-sections that represent the complex pore space observed in sandstones. We model wettability alteration after primary drainage and allow any values for the advancing and receding oil/water, gas/water and gas/oil contact angles. Multiple phases can be present in each pore, in wetting and spreading layers, as well as occupying the center of the pore space. In all, twenty different generic fluid configurations for two- and three-phase flow are analyzed.
With a network based on a description of Berea sandstone we can predict relative permeabilities for two-phase flow in a water-wet system and waterflood recoveries for mixed-wet media. We then predict the steady-state oil, water and gas three-phase relative permeabilities measured by Oak.1 We demonstrate that the predictions obtained by the network model compare favorably with those obtained using standard empirical relative permeability correlations.
We then study gas injection into media of different wettability and interpret the results in terms of pore-scale displacement processes.
Field Scale Research on Gas Chamber Pumps
Authors: Hernandez Ali , Reyna Marcelo 
Published: December 2007

Abstract
Recent experimental studies on intermittent gas lift have shown that the lift efficiency of this method decreases drastically as the viscosity of the fluid to be lifted increases. As the viscosity increases more gas is needed to keep the fallback losses at a minimum. One way to get around this problem and eliminate fallback losses is to implement the use of Gas Chamber Pumps (GCP's).
GCP's are highly appropriate for shallow wells producing heavy oil in places where high-pressure injection gas is available. That is the case of some wells in Lake Maracaibo and in some places in the eastern oil fields in Venezuela that are currently producing oil of 14 to 23° API from reservoirs located at depths between 2000 and 3500 ft.
A variety of different GCP configurations can be found in the literature, from highly complex and compact units to simple types of completion that can be implemented with minor changes of current gas lift completions. The advent of simple and highly reliable programmable surface controllers is making it possible to simplify subsurface completion. The simplicity of these new completions implies a new and economical way of implementing GCP's where they are appropriate. Furthermore, a new mathematical model to estimate the liquid production and gas consumption of a well producing with a GCP was developed recently and presented in the literature (paper SPE 69401).
A new field scale research conducted on GCP's is presented in this paper and a comparison of the actual measurements with the mathematical model outcome is included.
Use of Settable Spotting Fluid Improves Expandable Casing Process—Case History
Authors: Owoeye Oladele O. , Onwuta Victor O. , Erivwo Ochuko E. , Griffith James , Nida Ron 
Published: December 2007

Abstract
This paper presents laboratory and field data for using a settable spotting fluid (SSF) to help improve the subterranean zonal isolation of primary cement jobs on expandable liner installations. A SSF can add value to the well construction process when well conditions for cementing are less than optimal; i.e., low annular velocity, no pipe movement, poor casing centralization, or poor mud conditions. Many of these unfavorable conditions are present when expandable casing is installed.
Past SSF designs used blast-furnace slag and were limited to temperatures less than 90°F (32°C). The new SSF incorporates a hydraulic material with a non-blast furnace slag and is formulated for water-or oil-based wellbore fluids. Although the new SSF is optimal for displacement in the cementing process, the SSF will set to a state for providing zonal isolation if it is bypassed during the cement displacement process. Depending on the time required to run and expand the casing, the SSF can be formulated to remain liquid for a few hours or as long as three weeks. However, the high pH condition and heat of hydration from the placed cement in the annulus can accelerate the set of the SSF to a few hours.
The achievement of a near-100% annular seal occurs even when poor cementing conditions are present and without the use of rheologically tuned spacers. Job data from field trials also show improved shoe integrity and higher pipe-to-cement bond, echoing the results from the laboratory tests.
Feasibility Assessment of a New Approach for Integrating Multiscale Data for HighResolution Reservoir Characterization
Authors: Reeves Scott R. , Mohaghegh Shahab D. , Fairborn John W. , Luca George 
Published: December 2007

Abstract
The ability to accurately and fully characterize subsurface oil and gas reservoirs remains an elusive target for the energy industry. By accurately we mean with less uncertainty and at a higher spatial resolution than today's state-of-the-art, and by fully we mean in continuous, threedimensional space. The benefits of achieving this objective are obvious; field development plans and enhanced recovery operations can be optimized, and bypassed hydrocarbon pools can be identified and targeted for production. Ultimately, this should translate into an improvement in ultimate recovery factors from existing fields from the current (U.S.) average of only about 35%.
A research project funded by the U.S. Department of Energy has recently been completed to demonstrate the feasibility of a new approach to achieve the above objective. In summary, a series of relationships, founded on artificial intelligence technology, have been established (both in this project and by others), between data of different scales and type, including conventional logs, reservoir imaging logs, cross-well seismic, and surface seismic. Specifically, relationships between conventional logs and imaging logs have been demonstrated, as have relationships between conventional logs and cross-well seismic, and finally between cross-well and surface seismic. Through their integration, a fully 3D reservoir image should be possible, directly in the engineering terms required for reservoir flow simulation (i.e., porosity, fluid saturations, and permeability), at an improved resolution over surface seismic alone, and with less uncertainty than geostatistical methods alone. The specific advantages of the new approach include: Improved vertical resolutionEliminates need for seismic attribute inversionInclusion of intermediate scale data (e.g., cross-well tomography) increases constraints and reduces uncertainty of reservoir descriptionFinal product presented in terms of reservoir engineering parameters needed for flow simulation
While the work performed to date has demonstrated the technical feasibility of achieving a next generation of highresolution reservoir characterization-using today's data collection capabilities-it has yet to be validated in an integrated manner at a single field, and reconciled with field performance via reservoir simulation. Further research along these lines, aimed at both improving and demonstrating the technology, and also funded by the U.S. Department of Energy, is currently underway. This paper presents the work performed to demonstrate the technical feasibility of the new approach for high-resolution reservoir characterization.
Natural Gas Liquids and LNG Production from Crudes and Wet Gases
Authors: Desouky S. M. , King Saud U. , Macary S. 
Published: December 2007

Abstract
The term Natural Gas Liquids (NGL) refers to a mixture of gases (ethane, propane butanes and pentanes), that can be extracted by multi-stages of compression and cooling. This work developed a mathematical model to simulate the production of NGL from Arab crudes and wet gases. The model consists of three sections. The first is the partial vaporization unit, in which the number of stages (N) depends on the determined optimum conditions. Second: partial condensation unit, from which the separated liquid passes into the third section-fractionation unit (demethanizer), where NGL is produced. The model accounts for the effects of the main operational variations such as operating conditions (pressure and temperature), number of stages to separate gases from crude (N), number of stages for liquid separation from associated and wetted gases (M), number of trays in demethanizer (T) and refrigeration energy (E).
The model gives optimum solutions for processing crude oils of different API gravity and for various feed conditions and gas-oil ratios. The applicability of such a model will be advantageous, particularly in Arab Countries, where the separator off-gases are flared.
Utilization of Geomechanics for Medusa Field Development, Deepwater Gulf of Mexico
Authors: Chhajlani Richin , Zheng Ziqiong , Mayfield David , MacArthur Bruce 
Published: December 2007

Abstract
The scope of applied geomechanics in the petroleum industry has been on the rise over the past decade. Geomechanics analysis has shown to increase the overall value to various projects and create positive technical synergies between various groups involved with project development. This paper highlights a comprehensive geomechanics study carried out on a deepwater Gulf of Mexico (GoM) field for optimizing field development with respect to critical drilling, completion and reservoir issues. A detailed and well-calibrated wellbore stability model applied to the Medusa field has shown to reduce the drilling operational costs by enhanced well planning. The log-based geomechanics models used to evaluate sand production and pressure dependent pore volume compressibility have aided in reducing project risks and increasing project life. The intent of the paper is to show the practical risk reduction and cost savings that are possible through geomechanics analyses in high-cost, high-risk projects in deepwater arenas such as the Gulf of Mexico.
Influence of Temperature and Clays/Emulsion Microstructure on Oil-Based Mud Low Shear Rate Rheology
Authors: Herzhaft Benjamin , Rousseau Lionel , Neau Laurent , Moan Michel , Bossard Frederic 
Published: December 2007

Abstract
Oil Based Muds are very complex fluids composed from water, oil, organophilic clays and various additives. Their very good filtration and lubricating properties make their use beneficial in numerous drilling operations. Deep offshore operations may present phases using Oil Based Muds as drilling fluids. In these operations, the mud will experience very low temperature (down to 0°C) and low shear rate when flowing through the riser. It is therefore of primary importance to control muds rheological properties under such conditions. This work presents a rigorous experimental study of Oil Based Mud rheological properties using scientific rheometers. Temperature dependence and low shear rate behavior are specially studied. Due to their complex nature, Oil Based Mud rheological properties will be extremely dependant on the microstructure of the composition. Characterization of this microstructure has therefore been sought during this study.
Several Oil Based Muds compositions have been investigated. Flow curves have been established with a precise and reproducible procedure at temperatures varying from 0 to 80 °C. For an offshore designed composition, a specific behavior at low shear rate has been detected; two different regimes can be seen: a newtonian behavior at low shear rate and an Herschell-Bulckley behavior at higher shear rate, the limiting shear rate value between the two regimes being dependent on temperature. Experiments on partial compositions (partial muds with/without solids, with/without clays) have shown that the specific clay used in this composition is responsible for this particular behavior at low shear rate. Oscillatory rheometry measurements have confirmed the existence of these two different regimes. CryoMeb and microscopic observations have allowed to estimate the size of the emulsion droplets and the clay particles; a simple energetic and structural model is proposed that fit well the data. Finally, a comparison is made between these experiments and those obtained using Fann35 rheometer; concluding that classical Fann35 measurements induces large error for low shear rate rheology.
Creating and Nurturing a Knowledge Sharing Culture in a High Performance Technical Group
Authors: Balnaves Charles , Busch Barbara 
Published: December 2007

Abstract
The Petroleum Engineering function at BHP Billiton bears primary responsibility for providing estimates of the company's oil and gas reserves and an understanding of the uncertainty surrounding them. Forecasting of production profiles, efficient completion design and analysis of data to calculate the number of wells and their placement ensure effective production. This paper is focussed on a hidden but critical success factor for the function - its knowledge sharing culture.
Since 1998 the business plan for the function has been specifically designed to meet the organisation's strategic needs by creating a global knowledge-sharing group to ensure that the 120 (approximate global contingent) staff are able to provide excellent, speedy and reliable results. This paper outlines how we have moved in four years from a largely regional, functionally isolated group to one which can move staff across the world quickly for short term projects, execute complex technical work successfully in virtual teams and respond within 24 hours (in many cases) to each others requests for assistance. Sharing our knowledge has become a natural part of the way we work.
This paper outlines the need for change and for alignment to the organisation's business imperatives. It also covers the issues that we faced in the implementation of the plan to move to the desired culture and the balance between organisational growth, maintenance of size and reduction in various offices. The vision, strategy and execution plans for practical implementation of cultural change are outlined along with examples of our success and remaining challenges.
Downhole Emulsion Problem, The Causes and Remedy, Ras Budran Field
Authors: Aziz Hany M. Abdel , Darwish Sameh F. , Abdeen Fathalla M. 
Published: December 2007

Abstract
Ras Budran (R/B) field is located 5Kms. offshore at the eastern coast of the Gulf of Suez and consists of a massive Nubian Sandstone Reservoir compartmentalized by partially major faults. The field is undersaturated and production is maintained by gas lifting while the pressure is supported by a combined water flood and limited aquifer drive.
The R/B produced crude oil has an intermediate base with asphaltene content ranging from 10–15% wt and an average API Gravity 25°.
With the increase in water production and injected seawater breakthrough a very viscous tough emulsion was formed in some wells, causing production problems. Also, due to scale deposition, calcium carbonate and sulphate, the hydrochloric acid and other scale dissolvers were applied to clean the tubing and the formation. Some of these additives have an adverse effect on the emulsion viscosity and cause asphaltene deposition.
The paper presents the study carried out to identify the problem and find a solution for it. The study includes: ◊The rheological properties of the emulsion at different downhole conditions; shear rates, temperatures and water contents at different salinities.◊The effect of the different chemicals used for scale removal and inhibition on the asphaltene deposition and the produced crude oil emulsion viscosity.◊The effect of the flow improver products; demulsifier, Asphaltene dispersant, viscosity and drag reducers…etc. on increasing the fluidity and reducing the drop in pressure of the produced crude oil emulsion.
The study results showed that the hydrochloric acid causes asphaltene deposition and tough emulsion formation. Also the increase in the water content form a very tough/viscous emulsion at a certain percentage, which is defined as the inversion point, below and above this percentage the emulsion viscosity is reasonable.
The injection of the flow improver chemicals through the gas lift valves could reduce the emulsion viscosity.
Optimized Decision Making through Real Time Access to Drilling and Geological Data from Remote Wellsites
Authors: John Zachariah , Ahsan Abul , Reid Ian 
Published: December 2007

Abstract
Effective two-way communication and data flow between rig and office is essential to optimise decision making in offshore operations. Traditionally, during drilling operations, engineering, geological and formation evaluation while drilling (FEWD) data was only available at the Operator's office via morning and afternoon reports, email, shared folders and telephone. Information technology has now evolved to a stage where office-based geologists and engineers can monitor and evaluate wellsite data in real time using the Internet and any standard web browser. This enables domain experts to provide more effective support to the wellsite staff especially when critical decisions are to be made in a timely manner.
This paper describes how modern information technology such as InterACT (Formerly called InterACT Web Witness: or IWW) facilitates collaborative work in real-time on data being acquired from remote drilling wellsites. The availability of data real-time does create a paradigm shift in the way the asset team and contractors utilize data for early decisions. Challenges, benefits, and lessons learnt on the implementation and application of this technology are highlighted through examples where this technology was used namely: Echo/Yodel development drilling campaign (Woodside Energy Ltd.) for Geosteering Decisions and Melville-1 exploration well (Bass Strait Oil Company Ltd) for monitoring drilling, FEWD and wireline logging.
Experiences from these two projects gained by Schlumberger can be utilized by other companies to put in place a data flow model incorporating real time data.
Numerical Simulation Studies of Thermally-Induced Gas Production from Hydrate Accumulations with No Free Gas Zones at the Mallik Site, Mackenzie Delta, Canada
Authors: Moridis G. J. 
Published: December 2007

Abstract
The Mallik site represents an onshore permafrost-associated methane hydrate accumulation in the Mackenzie Delta, Northwest Territories, Canada. This study focuses on gas production at the Mallik site from hydrate deposits that are underlain by either a free water zone or by an impermeable boundary. The production analysis was conducted using a numerical simulator that can model the non-isothermal CH4 release, phase behavior and flow under conditions typical of CH4-hydrate deposits by solving the coupled equations of mass and heat balance. The simulator can describe any combination of the possible dissociation mechanisms (i.e., depressurization, thermal stimulation, salting-out effects and inhibitor effects). Accumulations with a CH4-hydrate saturation of at least 50% were studied. Dissociation was induced mainly by a combination of thermal stimulation and depressurization as hot fluids circulated between injection and production wells. The effects of salinity and of pressure changes at the wells were also accounted for. The production strategy resulted in a zero net water production. The simulation results indicated that the amounts of CH4 released from the dissociating hydrate deposits is sensitive to the hydrate saturation, the initial temperature, the specific enthalpy and the flow rate of the circulating fluids.