bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Infinitely Variable Choke for Multi-Zone Intelligent Well Completions
Authors: Williamson Jim R. , Bouldin Brett , Purkis Dan 
Published: December 2007

Abstract
State-of-the-art completion technologies to more efficiently support the needs of the oilfield continue to be developed. For example, intelligent completion techniques, which are designed to allow the operator to reconfigure well architecture without well intervention, have gained a great deal of attention because of their capabilities to improve monitoring and overall well performance in multi-zone oil and gas field developments. In all of these multi-zone intelligent-well completions, flow adjusting and monitoring devices or interval control valves are located between zonal isolation packers to control flow into or out of each zone.
The first generation of these interval control valves was a choke that offered only four positions. To overcome the position limitations, an infinitely variable choke has now been designed. The requirements for this next-generation interval control valve provided many design challenges. This paper describes the design, development and testing of a metal-to-metal sealing, infinitely variable downhole choke with true position sensing capability. All topics from the conceptual design and customer requirements to accelerated erosion testing and component life predictions will be discussed. Testing has verified that the new interval control valve can support the needs of the multi-zone well completion. This new technology has been installed in a Statoil water injection well.
Low Cost Horizontal Well Design and Implementation: A Case Study from the Kenmore Oil Field, Eromanga Basin
Authors: Hedger L. K. , Lansom P. B. , Trethowan E. , Anthony D. P. , Arnold A. , Gillibrand J. 
Published: December 2007

Abstract
This paper describes an unusual well design that has been implemented in a mature onshore oil field to minimise the cost of development drilling, improve well performance and utilise existing infrastructure. Horizontal wells were proposed to maximise oil recovery from the thin remaining oil column in the Kenmore Field, which has a strong bottom water drive. The challenge was to design horizontal wells that cost no more than low cost vertical wells. The drilling project was completed in January 2000, with the lessons learnt widely applicable.
Foam Properties Requirements for Proper Hole Cleaning While Drilling Horizontal Wells in Underbalanced Conditions
Authors: Martins A. L. , Lourenço A. M. F. , de Sá C. H. M. 
Published: December 2007

Abstract
This paper summarizes an extensive experimental program developed at PETROBRAS R&D Center, as part of the JIP named "Lightweight Fluid Drilling from Floating Platforms". The lab work steps include foaming agent selection (considering optimum concentration and salt/oil contaminants), rheological characterization of foams, development of a flow loop to test foam carrying capacity in high angle wells, definition of test procedure and matrix, besides discussion and analysis of results. Besides, based on results obtained from a numerical simulator, a comprehensive and useful model for predicting hole cleaning while drilling under-balanced or near balance with foams is proposed. After about 50 bed tests performed in PETROBRAS cuttings transport flow loop, correlations were proposed to predict cuttings bed erosion capacity in horizontal wells as functions of foam quality. Based on the experiments and on a mechanistic model for cuttings transport, foam rheology and stability requirements for drilling vertical, inclined and horizontal wells in underbalanced and near balance conditions were established.
A 3-D Numerical Model for Designing and Planning of Matrix Acid Stimulation in Low-Permeability Rocks
Authors: Chen Zhixi , Nguyen Desmond , Rahman Sheik S. 
Published: December 2007

Abstract
Based on material balance and theory of surface reaction kinetics in porous media, a 3-D numerical model was developed to predict changes in rock properties due to acid stimulation. The simulator were then verified with experimental results from acidizing test conducted on core samples taken from a number of reservoir rocks. It was found that the simulator could adequately predict spent-acid concentration and changes in porosity and permeability as a function of penetration depth for given acid treatment conditions. We also demonstrated how the numerical model could be used to design and plan acid stimulation work for given reservoir conditions.
Fracture Porosity from Conventional Logs with Image Tool Calibration
Authors: Adams S. J. 
Published: December 2007

Abstract
Petrophysical evaluation of the Moki Formation in the Toka-1 exploration well, required rapid quantification of fracture porosities, enabling likely hydrocarbon volumes to be estimated. A resistivity imaging tool had been run over the approximately 400m of fractured interval. This information was being processed for fracture apertures by the acquisition contractor, but the rate of quantification was too slow to meet the operators objectives. A technique was developed to rapidly estimate fracture porosities using the difference between the density and the compressional sonic porosities and the difference between the shear and compressional sonic porosities. The fracture porosity estimates were cross-checked against the image log analysis completed. Owing to washouts across the most heavily fractured intervals, it was expected that fracture porosities from the density and compressional sonic logs were maximum values. The most likely fracture porosities were thought to be those derived using the shear and compressional velocities. The fracture porosities estimated by hand-picking fractures from the image data were considered the minimum values, since the identification process was incomplete. The work described represents a new technique for fracture porosity quantification. The comparison with image log interpretation over a short interval gives confidence in the methodology. The results are significant in that they show rapid quantification of fracture porosity is possible by using conventionally acquired logs, although it should be recognised that the uncertainty in this approach is significant. Application of this technique to other fields with limited image data may prove helpful in reservoir modelling and understanding of production behaviour.
The Stuart Oil Shale Project
Authors: McFarland J. D. , Hopkins P. D. 
Published: December 2007

Abstract
The A$250 million Stuart Stage 1 Oil Shale Project in Queensland, Australia is one of the most significant new developments in the non-conventional oil industry. The Stuart Project is a joint venture between Australian companies Southern Pacific Petroleum N.L. and Central Pacific Minerals N.L. (SPP/CPM), and Canada's Suncor Energy Inc. (Suncor). An important milestone was reached in 1999 with completion of construction of the Stuart Stage 1 technology demonstration plant. This 4,500 b/d (715 m3/d) plant, constructed by Bechtel, is currently being commissioned by Suncor, the project operator.
The Stuart oil shale deposit has an estimated in situ resource of 3 billion barrels of shale oil. The Stuart Project incorporates the Alberta-Taciuk Processor (ATP), a new generation of oil-shale retorting technology which was chosen following a A$150 million R&D program in the 1980s. Upon technical and operational success in Stage 1, the next step is to scale up the ATP in Stage 2 to a commercial sized module producing 15,000 b/d (2,350 m3/d). This could lead to a commercial scale operation of at least 85,000 b/d (13,500 m3/d).
Success at Stuart will have important implications for Australia in terms of job creation and development of a new source of indigenous oil supply. It could also be important for world oil supply given the immense size of the world's oil shale resource.
Reservoir Management and Discovery of ‘New’ Oil in an ‘Old Field’: A Case Study
Authors: Rajkhowa Anupam , Jena Sampad K. , Ravichandran V. 
Published: December 2007

Abstract
The Moran oilfield is one of the oldest oilfields of the Upper Assam basin, which is a part of the Assam-Arakan geological province. This field located in northeastern India, has been on production since late fifties from clastic sandstone reservoirs of Barail group of Oligocene age. The reservoirs deposited in fluvio-deltaic environment, occur as multi-stacked channel sands in a depth range of 3200-3600 m. Recovery so far from these reservoirs has been around 29% of OOIP and the field is currently producing 350 cum/day of oil as against a peak plateau production rate of about 2500 cum/day. The case history describes reservoir management of the field and highlights success of recent exploration in terms of discovery of deeper oil prospects in the field. Commercial discovery of ‘New’ oil in the ‘Old’ field in the very first exploratory well has raised prospects for better utilisation of existing infrastructure facilities.
In order to accurately define the sand channel geometry, supplement ongoing reservoir management measures in the producing Oligocene reservoirs, and also to explore the deeper Eocene prospects, 3D seismic has been acquired during 1998. The 3D seismic data integrated with a large number of Oligocene well evidence has resulted in refinement of the sand channel geometry and identification of fairly large structures at Lower Eocene level. Oil has been discovered in the very first test well drilled on the deeper Lower Eocene structure within Lakadong member of Sylhet formation at a depth of about 4650 m. The discovery of this new hydrocarbon play has resulted in additional reserve growth of significant potential. Plans are in hand for development of Moran field for Lower Eocene prospects simultaneously with enhancing recovery from shallower Oligocene reservoirs.
Trunklines on Rugged Seabeds - Application of Technology to Quantify and Reduce Costs
Authors: Fogliani A. J. , Smith N.T. G. 
Published: December 2007

Abstract
The high cost of constructing and maintaining a large offshore pipeline system over rugged seafloors means that particular attention is required to achieve an accurate cost estimate and an economic design. In many cases the feasibility of a field development will be revisited as technology catches up with the specific requirements of the project. Advances in survey equipment, digital terrain modelling of three dimensional bathymetric data and the integration of spanning analysis models allows the engineer to optimise route selection, minimise high cost intervention works and more reliably estimate project costs.
This paper identifies and reviews the key cost drivers of strategic trunkline projects, the implications of rugged seabed features and the benefits of route optimisation technology. The paper outlines methods for the implementation of route optimisation technology and particularly addresses the interactive application of the technology during the survey works. The benefits of teamwork and interaction between the survey team and the pipeline engineering team are highlighted. This paper includes a list of applications and also outlines proposed future development of the technology.
Overcoming Completion Challenges with Interventionless Devices - Case Histories of the "Disappearing Plug"
Authors: Larimore David R. , Huggins Jeff , Robb Ewan , Ching Willie , Thomson D. W. , Jennings John , Bach Terje 
Published: December 2007

Abstract
The ongoing need for greater operational cost efficiency has encouraged oil companies to seek new methods that can simplify completion processes and reduce the number of required well interventions. This focus has resulted in new challenges for engineering/manufacturing and service companies to develop multi-functional equipment. To meet these challenges, a new generation of completion equipment with capabilities that would have been considered impossible ten years ago has been introduced to the oilfield. This equipment has been designed to not only reduce the number of interventions normally required in traditional completion scenarios but also to meet challenges of safety and reliability that can surpass the cost of contingency measures should the product fail.
The development of one such device, the "disappearing plug," which serves as a plugging device for setting a hydraulic-type packer, will be the focus of this paper. When run in with the completion, the tubing will fill automatically through an auto-fill device, and then, will close during one of the pressure cycles. The fluid-expendable plug material disintegrates on the last pressure cycle, which allows full- tubing-drift production and eliminates the need for a slickline or coiled-tubing run to retrieve a plugging device as would be the case with conventional methods.
While the industry average for successful installation of interventionless devices has still not reached the sought-after 100% reliability, when these concepts have been successful, the expected economic job goals have been surpassed. When successful in offshore, horizontal, and/or high angle wells where slickline or coiled tubing intervention after completion is significantly more costly, these interventionless technologies have proven to be even more beneficial.
The paper will discuss development of the plug, some of the failures that occurred, how these difficulties were addressed, and finally, will discuss several recently run installations. These clearly show the extent of the economic benefit that can be realized.
Disappearing plug technology currently improves economics by eliminating the need for slickline and coiled- tubing interventions in plugging operations. When setting hydraulic packers, this not only reduces operating costs but also the risks associated with interventions and plug failures. One of its most significant contributions, however, becomes apparent when considering the future trends of the industry — interventionless and intelligent well technologies. The disappearing plug will undoubtedly play an important role in the actualization of these future well trends.
The Application of Modern High Quality and High Speed Drilling Technology in SZ36-1 Oil Field Development of Phase II in Bohai
Authors: Wei Jiang 
Published: December 2007

Abstract
This paper mainly describes the application of modern high quality and high speed drilling technology in SZ36–1 oil field development and construction of phase II, and summarizes the innovation spirit and achievement during the project. The drilling project had highlights as follows. Firstly, the distribution of cluster wells becomes denser. The distance between wells had been reduced from 2m%2m to 1.5m%1.8m. Secondly, the number of wells in platform was more than 35 wells and the controlling oil reservoir area had increased more than two times. Finally, the quality and efficiency of drilling operation has achieved new level. The drilling operation of three wellhead platforms with three platforms spent 246 days of drill platform. The total numbers were 78 wells and footages were 149946m. The average depth per well was 1922m and average operation period is 3.15 days per well. The quality of all wells is perfect. During the operation, broke through four records of China National Offshore Oil Corporation (CNOOC) in production well ten times and create 1.61 days new record that is the shortest operation period. Compared with the other wells, the drilling efficiency and operation period reached the best level of CNOOC. It provided helpful suggestions and experiences for the future development and construction of oil field.
Geological Knowledge Data-base of Fan-delta
Authors: Jia Ailin , Mu Longxin , Huang Shiyan , Chen Liang , Zhang Chuanlan 
Published: December 2007

Abstract
In the period of maturing oil field development, on one hand, water saturation becomes higher and higher, on the other hand, lots of moveable oil still stays in the reservoir. The main reason for this case is determined by the variation of the reservoir, so the main job for geologists is to know the heterogeneity and continuity of the reservoir. In this case, the well spaces are about 200-300 meters. In order to give a relatively reliable prediction of the reservoir variation between wells, we must build a prototype model and know the real condition of the reservoir. During the past 5 years, we have studied the fan-delta outcrop and built a very detailed prototype model and established sets of geological knowledge databases, which include lithology database, microfacies database, sandbody scale database and many geological statistic databases.
According to these useful databases, we can predict the heterogeneity and oil saturation of maturing oilfield in different blocks and different layers. A few wells have been drilled according to our prediction through prototype model, and the oil saturation is 5-7 times higher than the old wells. Prototype model is very useful in the oilfield reservoir heterogeneity prediction, which have the same or similar depositional environment. In order to predict the reservoir variation of different depositional reservoir, series of prototype models must be built.
Experimental Study on Friction Pressure Drop for NonNewtonian Drilling Fluids in Pipe and Annular Flow
Authors: Subramanian R. , Oklahoma Tulsa , Azar J. J. 
Published: December 2007

Abstract
An extensive experimental study on friction pressure drop for nonNewtonian drilling fluids in pipe and annular flow was conducted. A fully instrumented 350 feet flow loop, consisting of two pipes and two annular flow test sections, was used in the test program. Five different muds were tested, which included: Bentonite mud, MMH mud, polymer mud, Glycol mud and Petrofree vegetable oil mud.
The experimental data obtained were used to generate very useful plots of "friction factor" versus "generalized Reynolds number". For each of the mud systems, the plots offer a practical and accurate means in determining needed friction factors for the calculation of pressure drops in pipe and annular flow. In addition, a comparative discussion is presented on measured friction pressure drop data, predicted by correlations such as the power law, Bingham plastic and yield power law. The importance of wall roughness on turbulent flow friction pressure drop calculations is also investigated.
Screening Variables for Multilateral Technology
Authors: Brister Ray 
Published: December 2007

Abstract
The multilateral well was one of the leading technologies of 1999, and it will continue to be one of the leading technologies for the next 5-10 years. It is likely that because of the cost reduction driver, management will ask, "Why isn't this a multilateral well?" much like the current justification for horizontal wells. The two challenges in 2000-01, unmet in 1999, will be consistent success of the technology and the low cost multilateral.
When evaluating multilateral technology, it is important to understand three things. First, in its simplistic scenario, the only difference between a multilateral well and a sidetrack or redrill is that the original wellbore will remain open when placed on production. The second thing to note is that multilateral technology is a reservoir development technology rather than a drilling technology. The drilling department is simply the vehicle by which this reservoir technology is brought to fruition. And third, all major operating companies will utilize multilateral technology; the question of consequence is ‘when?’.
The purpose of this paper is to present the first steps in applying multilateral technology to the operator in a practical way. This paper will cover only one aspect of multilateral technology – screening variables. These screening variables should be viewed as fundamental criteria from which, to begin a multilateral feasibility study. One of the screening variables is the driver for multilateral technology. Since the business driver must be evaluated before any other screening variable, it will be covered first. The remaining variables will be covered according to the order in which they appear in the planning, design, and implementation of a multilateral project. The completion variables will be specified first, followed by reservoir and geological screening variables.
Finally, drilling and other general screening variables will be covered. Discussion of the different classifications or levels of multilaterals is taken from the TAML (Technical Advancement of Multilaterals) Classification system (Chambers1, Mackenzie and Hogg2).
Guidelines for Efficient Spot Fluid Displacement in Highly Inclined and Horizontal Wells
Authors: Martins A. L. , Sansoni U. , de Camargo J. W. , de Oliveira S. F. 
Published: December 2007

Abstract
Differential pipe sticking is still today a challenging problem in horizontal well drilling. The main focus of this paper is the analysis of the dynamics of substitution of a viscous fluid (the drilling fluid) by a less viscous one (the spot fluid) in a fully eccentric horizontal annulus. Initially, an experimental study aiming the determination of the flow rates required for the substitution was performed on a pilot scale flow loop using flow visualization techniques. The tests reproduced the drilling of 8½ in horizontal wells. An extra test was performed to reproduce the 12¼ in phase. Based on results obtained from a 2D simulator predicting the critical shear stresses in horizontal eccentric annular flows, a mechanism for the efficient displacement of spot fluids is proposed.
The Pilot Test of ASP Combination Flooding in Karamay Oil Field
Authors: Qi Qiao , Gu Hongjun , Li Dongwen , Dong Ling 
Published: December 2007

Abstract
The chemical screening and chemical formulation studies were discussed in this paper, and the pilot test results as well for the ASP combination flooding pilot test in Karamay EZ District. Also the designing strategies of the ASP process were included in this paper. The ASP pilot test started from August 21,1995 with the beginning of NaCl brine pre-flush in order to condition the reservoir, then followed by ASP slug and Polymer slug. The post-water injection was applied after the designed chemical injections. The 24%OOIP incremental oil recovery was achieved in the whole test area with about 25%OOIP incremental oil recovery for the central production well.