bluuebunny/crossref_metadata_2025_split huggingface dataset:
Combination of Snake Well Design & Smart Completions: Key Enablers for Champion West Development
Authors: Johan Aidiradiman Haji , Schrader Kirby 
Published: December 2007

Abstract
This paper describes the combination of the snake well concept and intelligent completions, the introduction of which became the key enablers in developing the Champion West field. The field is characterized by uncertain fluid fills, thin multi-layered and intensely faulted reservoirs with complex fill distributions that include thin oil rims below large gas caps. The key success factors for such a development are the integration of multi-discipline approach in optimising the best development plan, real time interpretation of "reverse" logs, managing the mud rheology, records of drilling parameters for torque and drag and lastly but not the least, the robustness and flexibility of the completion design. All of the above are significantly beneficial as lateral learnings and findings for the Champion West Phase 2 & 3 development plan.
Mitigating Gas Hydrate Related Drilling Risks: A Process-Knowledge Management Approach
Authors: Prassl W. F. , Peden J. M. , Wong K. W. 
Published: December 2007

Abstract
In order to secure future energy needs, exploration for hydrocarbon reservoirs occurs increasingly in Arctic and Deep Water Environments. These two drilling environments establish temperature-pressure conditions that are favorable to gas hydrates. Gas hydrates are crystalline complexes of water molecules, which trap gas molecules of suitable size inside their lattice structure. If they are created inside the well system, they may block the BOP or lines, which leads to well control risks. When gas hydrates exist naturally inside formations, drilling activities may lead to their dissociation, which can result in borehole stability problems, serious well gasification or subsequent well integrity problems on production.
To mitigate these drilling risks a Process-Knowledge Management System (PKMS) has been developed. This PKMS allows the capture, verification, and intelligent use of explicit and tacit knowledge, and is constructed to allow exploitation of the knowledge from multiple field experts, company best practice policies, and latest technological findings. To incorporate and use the knowledge sources with embedded uncertainties, type-2 fuzzy set theory is applied. The PKMS is realized through individual reasoning blocks that set up a coherent reasoning lattice. The benefits of this approach are: An easy adaptation and upgrading of the system's knowledge, andSensitivity for selection of particular reasoning blocks, depending on the current drilling scenario and conditions, is sustained.
For the process of drilling within gas hydrate prone environments, the PKMS is actuated with multiple numerical simulations and gas hydrate related considerations. This paper discusses briefly the basic structure of the developed PKMS, as well as the numerical models used to describe the transient temperature field, the pressure profile and the gas hydrate kinetics applied.
Holistic Field Evaluations Improve Prospect Opportunities
Authors: Shelley Bob , Lehman Lyle , Grieser Bill 
Published: December 2007

Abstract
A holistic or overall reservoir performance perspective is seldom used in the well planning/decision process. The industry has a tendency to use broad generalizations along with uncertain interpolated reservoir information. Geologic complexity tends to turn these generalizations and assumptions into less-than-acceptable potential prospect performance predictors. In addition, the industry has a tendency to evaluate the reservoir and well drilling/completion process from a segmented or compartmentalized perspective. Numerous examples of this process exist. Petrophysicists, reservoir engineers, geologists, and drilling and completion engineers perform discrete evaluations based on their training and experiences in other reservoirs. Service companies are given incentives to concentrate on delivery/service issues and product revenue. Consultants focus on developing specific niches or completing assigned tasks. Single wells are analyzed rather than trying to understand how the well fits within the entire reservoir. Many operators grade themselves on their ability to drill and complete for less than industry standard. Their focus is on well cost.
What the industry needs is an understanding of how all these issues fit into the big picture. The subject of this paper is a summary of field evaluations performed to provide a holistic perspective. Results are presented that show how these efforts have identified significant reservoir opportunities with resulting productivity and prospect economic improvement.
The evaluations presented in this paper are holistic in nature and were performed by a team of experts. These evaluations consist of field data quantification, integration, enhancement, statistical and visual analysis, dimension reduction, and development of a predictive artificial neural network (ANN) model. The ANN model is used to identify patterns and trends related to the geology and to reservoir and well completion issues. Economic assessments of various completion/stimulation methods are presented. Engineering evaluations are performed to resolve difficult interpretation issues and test conclusions. The resulting information was then used to drive changes in well completion/stimulation procedures, which in some cases doubled the prospects value. This paper will illustrate the benefits of taking a holistic approach to field-wide problem solving.
Electrical Transport Properties of Fluids Saturated Porous Rocks by 2D Lattice Gas Automata
Authors: Guo Tao , Yue Wenzheng , Li Baoton , Fang Chaoliang 
Published: December 2007

Abstract
We have studied the electrical transport properties of porous media and the physical meaning of Archie's parameters with 2D Lattice Gas Automata (LGA). Based on our simulations we have developed a set of new equations to calculate fluid saturation from electrical measurements. The calculations from the new equations show very good agreement with laboratory measurements and published data.
Using a Modified Brooks-Corey Model to Study Oil-Water Relative Permeability for Diverse Pore Structures
Authors: Goda H. M. , Behrenbruch P. 
Published: December 2007

Abstract
Understanding the significance of apparently different relative permeability relationships is paramount in the assessment of recovery efficiency for a particular field. Apart from the normal difficulties encountered in measuring relative permeability, Australian rocks tend to exhibit considerable diagenesis, often showing clay-filled pores (kaolinite or dickite). This means that fines movement and other related phenomena are often encountered, leading to non-representative testing results.
More generally, relative permeability is a function of several key parameters: pore-scale geometry (including porosity and permeability) and pore distribution (pore-scale heterogeneity), rock-fluid interaction (mineralogy, capillarity and wettability), initial fluid saturation distribution, and fluid velocity (or capillary number, when combined with fluid viscosity and interfacial tension). In some cases more severe heterogeneity, e.g. layering or fractures, may be manifested. Also, defining suitable relative permeability relationships for a particular field requires validation and integration, particularly when conflicting data is available.
This paper introduces a new Brooks-Corey type approach to study relative permeability data for diverse rock types, for both onshore and offshore Australian fields, with particular emphasis on geological aspects. Data from several fields and laboratory tests have been analysed, covering standard testing methods. General conclusions are presented regarding validation and integration procedures. This analysis is believed to be unique in terms of the wide range and amount of data analysed for Australian fields. As an aid to understanding, extensive use has been made of petrographic images, and some of these are presented.
Impact of Dynamic Simulation on Establishing Watercut Limits for Well Kick-off
Authors: Mantecon Juan Carlos , Andersen Iris , Freeman David , Adams Mark 
Published: December 2007

Abstract
Dynamic well modelling can provide additional understanding and an improved process to: ensure a well is going to naturally flow during initial kick-off, and/orpredict the watercut limits for the restart/kick-off of natural flowing wells after a shut-in period.
As reservoir pressure declines and watercut increases, naturally flowing wells often require gas-lift (artificial lift) in order to 'kick-off' and flow them continuously. These wells will generally encounter kick-off problems at a lower watercut than their natural flow limit due to fluid segregation effects in the wellbore under static conditions. Therefore determining the kick-off limit is of primary importance to determine the optimum gas-lift (artificial lift) implementation schedule and its economic impact.
Static (steady state) well modelling is of limited use in being able to predict the effects of fluid segregation on kick-off. Dynamic modelling of the wells during kick-off, however, will indicate the associated flowing tubing head pressure (FTHP) that will enable the well to attain steady state flow as a function of well productivity index (PI), reservoir pressure and watercut.
This paper describes how dynamic modelling of four undersaturated oil fields using OLGA 2000 has been used to effect timing decisions of gaslift installation.
In order to verify that OLGA 2000 was a reliable tool for the simulations, total mass flow rates (oil, water and gas) from well test data were compared with the mass flow rates predicted by OLGA 2000. The OLGA models were able to match the well test data, providing some evidence that OLGA 2000 can be used to model well behaviour.
Dynamic well modelling has been found to be a useful tool in optimising costly gaslift installation timing and improve well completion design. This should minimise potential deferred oil production and optimise reservoir recovery. Dynamic modelling is also useful in identifying and understanding the key flow assurance issues during the well's life cycle.
The time at which the wells will not naturally kick-off is dependent on productivity index (PI), reservoir pressure, and watercut. The reservoir fluid properties are critical to the results.
For the four oil fields studied, it was found that wells were predicted to experience kick-off problems at significantly lower watercuts – anywhere up to 26% less, than for steady state flow.
Dynamic well modelling should be considered during the early phases of concept selection studies to implement gaslift in oil fields.
Remote Field Control and Support Strategy - Umbilicals versus Control Buoys
Authors: Christiansen P. E. , McKay S. A. , Mullen K. , Upston L. R. 
Published: December 2007

Abstract
This paper addresses the latest developments in remote field control strategy and focuses on long distance umbilical control versus the use of a control buoy located over the field. The paper provides an insight into both the technology and also the commercial key drivers for the selection of control strategy.
The historical development of umbilicals and control buoys is summarised. The relevant technologies are described, covering aspects such as buoy design, telecommunication options, onboard power, fluid storage and injection capabilities, operational issues including access and maintenance, and opportunities for workover activities. The discussion is supported by case examples drawn from a number of fields around Australia.
Water-Based Insulating Fluids for Deep-Water Riser Applications
Authors: Javora Paul H. , Wang Xiaolan , Stevens Richard , Pearcy Rick 
Published: December 2007

AbstractUncontrolled heat transfer from production tubing to outer annuli, especially in deep-water riser sections, can cause the deposition of sludge, paraffin and asphaltene materials and contribute to the formation of gas hydrates. It also can limit the shut-in time if there is a need to shut down the well for remedial operations. Generally, deep-water risers can be insulated externally, or alternatively, insulated by placing nitrogen gas into the riser annulus. In recent years, a new water-based thermal insulating fluid system with superior thermal properties has been developed and used in field applications. This new system provides an ideal rheological profile to significantly reduce fluid convection caused by temperature differential and to facilitate fluid placement into the riser annulus. This system has been successfully used as an alternative to the current insulation method in deep-water risers in the Gulf of Mexico.Laboratory-scale equipment and a full-scale test well were constructed to evaluate the thermal insulation properties of fluids. This paper will detail both testing procedures and methods. Steady-state heat transfer and cool down test results on the new insulation fluid will be reviewed for both set-ups. The results will be discussed along with the results from similar tests on conventional brine based packer fluid, current insulation fluids, as well as nitrogen (air) and argon. The full-scale test data will be discussed in relation to modeling wellbore heat transfer. Field cases in GOM are also summarized to demonstrate the effectiveness of this fluid system.
Maximising the Value of the North West Shelf Project Using the DIME Forecasting and Optimisation Tool
Authors: Yates Darren , Chong Lawrence , Dale-Pine Brigitte 
Published: December 2007

Abstract
The North West Shelf Venture Project (NWSP) produces LNG, domestic gas, condensate and LPG's for supply to a variety of customers in the Asia Pacific region. The integrated nature of the Project provides a key competitive advantage through being able to optimise the complete supply chain from reservoir to sales. Gas and liquids are produced and processed offshore with final treatment onshore to meet the required product specifications.
The challenge faced by the Venturers that own the NWSP is to optimise the current and future development of the North West Shelf assets to maximise value for venture owners and all its stakeholders e.g. Government. The reservoir portfolio is becoming increasingly complex and includes fields which have been in gas recycle mode to maximise liquid recovery, and fields that will in the near term and long term require compression to increase deliverability and access low pressure reserves and undeveloped oil & gas fields that represent opportunities to accelerate liquid production.
To facilitate Project wide optimization, Woodside Energy Limited, the operator, has developed a hybrid linear programming optimisation tool, DIME, (Data Integrated Management Environment) to generate long term production and cost forecasts. This paper outlines the far reaching impact of the development and use of DIME within the supply development division of the North West Shelf Venture, NWSV. To fully realize the strategic benefits of the tool the business processes, individual roles, skills and organisational structure of the supply development division have evolved with the DIME technology. A dedicated optimisation group facilitates the forecasting process & system optimization interfacing with key stakeholders from technical experts to the product marketing groups.
Multi-Rate Testing for Vertical Wells in Naturally Fractured Reservoirs
Authors: Tiab Djebbar , Boulenouar Djilali 
Published: December 2007

Abstract
Naturally fractured reservoirs are prolific producers since fractures provide the main path for fluid flow towards the wellbore. Conventional drawdown and buildup tests are not always practical due to various technical difficulties to maintain a constant flow rate during a drawdown test or the loss of production during the shut-in period of a buildup test. In this case multirate tests represent a practical and effective alternative. This paper presents a complete multi-rate test analysis methodology in naturally fractured reservoirs.
The convolution theorem was used to accommodate the change in the rate if the test is multirate. The integral method is used if the rate is continuously changing. It was found that the pressure derivative provides a powerful tool for analyzing multirate pressure transient tests. The Tiab's Direct Synthesis (TDS) technique, which uses exact analytical solutions to obtain reservoir parameters, was applied to different possible cases and the results were compared to those obtained from the other conventional techniques.
In the case of long series of constant flow rate, the log-log plot of pressure and pressure derivative using equivalent radial time or equivalent linear time give approximately similar results. If the wellbore storage effect is large, the error in the permeability (especially during the early radial flow) is greater mainly if the late radial flow is not observed. When the early radial flow is missing, the dimensionless storage capacity ratio ? and the interporosity flow parameter ? cannot be estimated using conventional methods. In such case, they can be determined only from the pressure derivative plot using the TDS technique. During a multirate test, the changing flow rate must be systematically recorded since it is an integral part of all the analysis equations.
Several examples were solved to illustrate the use of the techniques developed. The results show that the multiple rate tests and the TDS technique can be successfully used to characterize naturally fractured reservoirs.
Identifying Reservoir Fluids by Wavelet Transform of Well Logs
Authors: Yue Wenzheng , Tao Guo , Liu Zhengwu 
Published: December 2007

Abstract
The wavelet transform method has been applied to logs to extract the information on reservoir fluids. In addition to time(depth)-frequency analysis generally performed by the wavelet method, we have also performed energy spectral analysis for time-frequency domain signals by the wavelet transform. We have processed 42 models from an oil field in China using this method and subsequently have applied these rules to interpret their reservoir layers. It is found that identifications using the new method are in very good agreement with the results of well tests.
An Integrated Efficient Approach To Perform IPTT Interpretation
Authors: Xian C. , Carnegie A. , Al Raisi M. R. , Petricola M. , Chen J. 
Published: December 2007

Abstract
Interval Pressure Transient Testing (IPTT) with an advanced formation tester has been widely applied to measure vertical and horizontal permeabilities. The principles behind IPTT may appear straightforward. But the interpretation of IPTT in complex reservoirs, such as carbonates presents many challenges, most of which are related to uncertainties arising from the heterogeneous nature of such reservoirs.
A novel, generally applicable approach is proposed for interpretation of IPPT tests. The approach is integrated and efficient, and ensures that the most probably valid and/or valuable information is used and revealed by IPTT. The approach standardizes the complete interpretation procedure of IPTT in a heterogeneous reservoir, using if available, modern wireline logs (such as NMR and Imaging), dynamic data from wireline formation testers and any other relevant information (such as geological description, core data and local knowledge) as constraints on the interpretation. IPTT is also a multi-layer testing technique. An iterative method to define layering is incorporated in the approach to determine the most probable layering. Many types of possible information that can be used to constrain layering definition are classified. Principles and guidelines on using different sources of information to define and refine the layering are recommended. An advanced regression technology is used to get optimized horizontal and vertical permeabilities of reservoir layers. The key is to find as much useful information as possible to guide the regression. To this end, different sources of permeability are classified and used as initial estimates, for input to the regression. Practical skills to perform IPTT regression are also summarized. In many cases, the operating sequences of the formation tester are primarily designed for downhole sampling rather than IPTT. The complicated downhole sampling sequences can make the pressure responses of gauges complicated and noisy. Hence, a Quality Check (QC) procedure is also included into this integrated approach.
Examples from a carbonate reservoir are presented.
Simple Formula for Calculating Strength Degradation of Well Casings and Pipelines Due to Corrosion Pitting
Authors: Sun Kai , Guo Boyun 
Published: December 2007

Abstract
Corrosion develops pits and cavities at the surface of steel structures. Well casings and pipelines in the petroleum industry are subject to severe corrosion because of their exposure to seawater and corrosive fluids that are transported. Under operating conditions, stress concentration around the cavities determines pipe strength degradation that can significantly shorten the life; even cause premature failure of the well casings and pipelines. It is therefore highly desirable to know the stress concentration factor (SCF) for both designing and evaluating well casings and pipelines.
SCF analysis with any numerical method is still a tedious and time-consuming task for ordinary engineers. This paper presents an analytical method to determine SCF around cavities of various geometries at the surface of well casings and pipelines. Results of analyses show that the SCF increases with cavity depth. The SCF value remains between 2 and 3 up to a cavity depth of 0.8 times the pipe wall thickness, and it increases sharply with cavity depth after a 0.8 times of wall thickness is reached. This sharp increase is more significant for thin pipes than for thick pipes.
Zamzama Gas Field - Balancing Risk and Value
Authors: Jackson Mark A. , Jellis Robert G. , Hill Robin , Roberson Paul , Woodall Mark A. , Wormald Glenn , Jafri Naveed 
Published: December 2007

Abstract
The Zamzama gas field is located in the Kirthar Foldbelt, Sindh Province, Pakistan approximately 200 km north of Karachi and importantly, only 8km west of the existing Sui-Karachi pipeline (Figure 1).
Since discovery in early 1998, a number of innovative approaches to field appraisal, gas marketing, infrastructure rationalisation and field development have been undertaken. This has resulted in the successful completion of the initial development phase, Phase 1, with the Zamzama gas plant coming on stream in July 2003. In addition, plans are well progressed towards realising an incremental Phase 2 development.
Cornerstone to the success of development to date has been the implementation of an extended well test (EWT) of the exploration (Zamzama-1/ST1) and appraisal well (Zamzama-2), which came on line in early 2001. The EWT mitigated an entire host of perceived risks associated with a full development, with minimal financial exposure.
The Thylacine/Geographe Offshore Otway Gas Development
Authors: Boardman David W. , Begovich Bryon , Davids Andrew , Kelly Jonathan C. , Rehbock Renita D. , Winters Stephen J. 
Published: December 2007

Abstract
This paper describes the main characteristics of the Thylacine and Geographe gas discoveries in the offshore section of the Otway Basin, and the development plan to commercialise these fields. The paper highlights how the impact of the main subsurface uncertainties has been assessed and used to derive the development plan and reserves distribution. The major subsurface uncertainties affecting the development were found to be gas initially in-place (GIIP), permeability and fault transmissibility.