bluuebunny/crossref_metadata_2025_split huggingface dataset:
High-Speed & High-Efficient Development of an Extra-shallow Sea Oilfield
Authors: Sun Huanquan , Wang Shiyan 
Published: December 2007

Abstract
Chengdao oil field is a large oil-gas field, which is situated in a very shallow water area of Bohai Bay of China. According to the complicated maritime and geological situation, the compositive study method containing several kinds of appropriate new techniques has been applied in the course of researching work on the geology and engineering situation of the reservoir. For example: The technique of logging constraining seismic inversion has been applied to predict the fluvial sand body's scales. As a result, the coincidental rate of the total number of layers up to 88% and the coincidental rate of the total thickness up to 92%.On the base of the study in pilot test area, multiple techniques, such as reservoir simulation and economic evaluation, have been applied to optimize the developing plan and preserve the pressure levels of the reservoir. It can also be used to determine the reservoir productivity and predict developing project parameters. The coincidental rate of reservoir productivity is 97.8%.The application of enlarging well spacing and irregular well sites aiming at the main oil-hearing sand bodies has saved investment and improved economic efficiency.
The project of Shengli offshore oilfield productivity building has been established on the base of compositive study on the reservoir geology. It contains 33 Well Group, 119 wells totally. The successful ratio of drilling is up to 100% and the accumulated productivity is up to 2,480,000 tons. By present, a set of techniques appropriate to the development of very shallow water oil field has been formed and the high-speed and high-efficiency development of Chengdao oil field has been achieved by using it.
New Formula of Surge Pressure for Determining Safe Trip Velocities
Authors: Rubiandini R. S. Rudi 
Published: December 2007

Abstract
Operational problem that related to tripping in/out pipe or running casing into the well bore become more severe and complicated, as drilled hole get deeper and smaller4).
When the pipes or casing are run into the well bore with high velocities, it will produce high surge pressure (increasing hydrostatic mud pressure) in the well. If the maximum fracture gradient limits were exceeded, the formation would be fractured and would end up with lost circulation. At the same time, when pulling out pipe from the drilled hole with high velocities, it produced high swab pressure (decreasing hydrostatic mud pressure) in the hole which lead to kick. If the minimum pore pressure limits were exceeded, there would be a flow of formation fluid into the well bore.
Based on this condition, we need the optimum safe trip velocities by predicting the surge pressure in the hole to prevent the possibility of kick or lost circulation without forgetting the operating time saving factor.
The paper developed some of new simple formulas for determining surge pressure as a function of pipe velocities parameter, mud properties, pipes and hole sizes diameter.
The analysis and variation process using a range of data that commonly used in the field. Using a computer, combination of mud properties, pipe and hole sizes had been done to evaluate the approximate equations for the conditions most often encounter in field operation.
The result are some new simple formulas of surge pressure which are a function of moving pipe velocities that are corrected by plastic viscosity parameter, yield point, mud density, pipes and hole size diameter for many common condition in the field. Compared with Moore formula which not involving pipe velocities parameter, plastic viscosity and mud density would lead to inaccuracy of predicting the surge pressure. With Burkhardt formula that used a graphic in calculation, it was not efficient for field used and it could cause a human error when plotting the graphic. Theoretically for pipe velocities ranging from 20 - 600 ft/min, it was found that these formulas have a good accuracy and the most important think is the simplicity for field operation. Although there are some formulas that had been published, which use an iterating process in predicting the surge pressure for better accuracy, it is not efficient enough for engineers in the field because of its complexity.
Based on these formulas, the possibility of kick and lost circulation in tripping process or running a casing could be prevented by predicting the optimum safe trip velocities and also saving in time and operational cost.
Keys to the Successful Application of Hydraulic Fracturing in an Emerging Coalbed Methane Prospect - An Example from the Peat Coals of Australia
Authors: Badri M. , Dare D. , Rodda J. , Thiesfield G. , Blauch M. 
Published: December 2007

Abstract
Early stimulation work in Peat Field of Queensland, Australia involved application of cavity completion techniques to produce methane gas at commercial rates in the first wells completed in the reservoir gas cap. Early in the project life, cavity completion treatments resulted in promising and acceptable gas flow rates. However, excessive cost associated with this technique led to consideration of alternate stimulation approaches by the design team. The main objective was to achieve similar or better gas rates at the lowest cost.
Multi-seam nitrogen-foam stimulation was conducted in several wells of the Peat field to assess the effectiveness of this technique in terms of: (1) production enhancement and cost reduction; (2) location of the coal-seam intervals in the gas cap (i..e. gas-saturated coals) and; (3) improved completion efficiency.
To minimise the effects of tortuosity and multiple far-field fractures in addition to ensuring that each coal-seam interval received adequate treatment, a staged stimulation approach in combination with other remedies such as sand slugs and high injection rates was adopted and successfully applied.
Zonal Isolation was achieved through the use of the newly developed, easily drillable composite plugs that allow staged treatment with flowback capabilities.
Field data of representative Peat wells will be used to demonstrate the successful application of the hydraulic fracturing approach that resulted in methane gas rates that more than compete with the early cavity completion techniques either from a cost or production improvement point of view.
The following specifics are addressed in the paper: A novel fracture design approach and modeling of fracturing treatments that can be of value to a broad audience of operators and design engineers.Real-time fracture stimulation methodology, analysis, and execution.Remedies to minimize the near-wellbore tortuosity and multiple far field fractures to avoid premature "screenout" and carry the fracture treatment to completion.Chemical optimization of fracture fluid designed based on coal characteristics.Use of newly developed composite epoxy-glass fracture and bridge plugs that provide a more efficient and cost effective way to carry out staged stimulation treatments.Post-fracture production tests to estimate the nitrogen- foam fracture treatment effectiveness in multi-seam CBM wells.
Intervention in Wells with Buckled Production Tubing
Authors: Newman K. , McSpadden A. 
Published: December 2007

Abstract
Sometimes the production tubing in a well can be helically buckled due to problems with the completion design, completion hardware, or installation problems. When coiled tubing (CT), wireline (WL) or jointed pipe (JP) is run through helically buckled production tubing there is a significant risk of getting stuck. This paper discusses the impact of helically buckled production tubing on the forces required to perform an intervention in the well. The theory for these forces is discussed, and a practical example is presented.

Introduction
Production tubing that is in compression, and is thus helically buckled, is common. Though the production tubing is initially hung in tension, the increase in temperature due to production from the well sometimes causes the production tubing to compress and buckle. In other cases there is not enough tension applied when the well is completed, allowing the bottom portion of the production tubing to buckle.
When any through tubing intervention is performed in a well with buckled production tubing, care must be taken to avoid becoming stuck. Since this paper is being written for a CT conference, it will focus on CT intervention, but it is important to note that the same concepts apply to WL and JP.
The helical shape of the production tubing, and thus the intervention path, causes increases in the tension or compression due to the capstan or belt friction effect of the helical shape. This effect may cause the tension to reduce while running in the hole (RIH). As long as the CT does not go into compression (in which case it will likely lockup, preventing any further penetration into the well), the operator will simply see a reduced weigh reading on surface. However, upon picking up weight to pull out of the hole (POOH), the increased tension due to the capstan effect may be greater than the breaking strength of the CT. Thus, the CT can be RIH but can become stuck when trying to POOH.

Theory
The buckled production tubing causes a modified form of the "capstan effect" sometimes known as the "belt effect". The increase in tension or compression due to this effect can be expressed as:Equation 1.1
Equation 1.1 must be included with the other vector forces due to gravity and wellbore curvature in a tubing forces model (TFM) for practical use. The period of the production-tubing helix will vary along the length that is buckled. The TFM must be run for the production tubing to determine the period versus depth in the well.
Hydraulic Pumping Units for Offshore Platform
Authors: Zhou Zhiqi , Hu Chen , Song Kaili , Li Xinhua , Gao Guangqi , Yang Juanhua , Fan Chunyu , Feng Hui 
Published: December 2007

Abstract
This paper introduces a hydraulic pumping unit for offshore platform that has been developed by Shengli Petroleum Administration and successfully applied to the oil field. This pumping unit adopts closed return circuit. In order to reclaim power and save energy, two sets of accumulators are set respectively at the entrance and exit of the hydraulic power pump. The energy is stored in the accumulators during the down stroke and the stored energy is released to lift the oil well load during the lift stroke. This pumping unit adopts the unique full hydraulic reversing and controlling return circuit, the hydraulic cylinder is set in the working barrel under the wellhead. In order to collect the signal of the piston arriving the top and bottom dead center, the both stroke holes are set in the inner tube of the hydraulic cylinder. The wellhead's installation area and height are equivalent to the flowing wellhead's. The height of this wellhead is less than 3 meters measuring from casing head. The structure of the hydraulic station is compact, the area that it contains is small, so it can be used on the offshore platform which area is limited. By developing of the hydraulic pumping unit for offshore platform, the mature technology in sucker rode oil production mode will be applied to offshore oil production, its application will greatly extend well repair cycle and obtain enormously economic benefit.
Experimental Investigation of CO2 Gravity Drainage in a Fractured System
Authors: Li Hujun , Putra Erwin , Schechter David S. , Grigg Reid B. 
Published: December 2007

Abstract
Traditionally, CO2 injection has been considered an inefficiënt method for enhancing oil recovery from naturally fractured reservoirs. Obviously, it would be useful to experimentally investigate the efficiency of waterflooding naturally fractured reservoirs, followed by CO2 injection, before this procedure is applied to a reservoir. This issue was investigated by performing water imbibition followed by CO2 gravity drainage experiments on artificially fractured cores at reservoir conditions. The experiments were designed to illustrate the actual process of waterflooding and CO2 gravity drainage in a naturally fractured reservoir in the Spraberry Trend Area in west Texas, USA.
The results demonstrate that CO2 gravity drainage could significantly increase oil recovery after a waterflood. During the experiments, we also examined the effects of different parameters such as permeability, initial water saturation, and injection schemes. We found that the efficiencies of the CO2 gravity drainage decrease as the rock permeability decreases and the initial water saturation increases. Cyclic CO2 injection helped improve oil recovery during the CO2 gravity drainage process after water imbibition.
Oil samples produced in the experiment were analyzed using gas chromatography to determine the mechanism of CO2-improved oil production from tight matrix blocks. The results show that lighter components are extracted and produced early in the test.
The results of these experiments validate the premises that CO2 will recover oil from a tight, unconfined Spraberry matrix.
Reservoir Characterisation and Evaluation of Micaceous Sandstone of Geleki Field, Upper Assam, India - An Integrated Study
Authors: Kumar Pardeep , Sharma S. C. , Roy U. S. , Sud V. K. 
Published: December 2007

Abstract
Tipam sandstone, the main hydrocarbon-producing reservoir of Geleki Field located in Upper Assam, India, is of highly complex nature containing good amount of mica (Muscovite) in addition to quartz, feldspar and montmorillonite as inferred from sedimentological studies. Mica complicates log analysis as most lithology indicators reflect it as high-density shale, resulting in pessimistic reservoir evaluation.
Mica is often misinterpreted as shale by common clay indicators used in conventional deterministic interpretation models based upon Density-Neutron-GR logs. However, mica should be considered as structural part of the rock not affecting porosity and permeability. Surface of mica is altered by diagenesis and acquires surface conductance leading to reduced resistivity of the formation even at constant porosity. Therefore, if mica is not included in lithological model the evaluation can be misleading. Further, high computed shale volume will make good reservoirs either appear worthless or with reduced potential.
In the present paper, the influence of mica on various log responses has been analysed, based upon which a highly micaceous sandstone facie has been identified in the upper portion of the reservoir. However, presence of mica and feldspar in moderate proportions is inferred throughout the formation. Multi-mineral interpretation model based upon statistical inverse modeling technique has been successfully used for realistic evaluation of reservoir parameters leading to identification of new hydrocarbon bearing layers.
Oil production from a well tested on the basis of the present integrated study has confirmed the efficacy of the suggested model. Extension of the model to other similar reservoirs can lead to better reservoir characterization and delineation of by-passed hydrocarbons.
Investment and Risk Analysis Applied to the Petroleum Industry
Authors: Motta R. , Caloba G. , Almeida L. , Moreira A. , Nogueira M. , Cardoso L. , Berlink L. 
Published: December 2007

Abstract
In Brazil, for the last four decades, Petrobras, a state-owned company, had retained a monopolistic concession for the exploration of Oil & Gas prospects, when, in 1998, the law was changed and a broad range of opportunities were created. Since then, Petrobras has been offering a series of Join Venture opportunities for foreign oil companies to farm in.
Presently, a number of international oil companies installed offices locally and started to participate in the upstream sector. ANP, the National Petroleum Agency, is offering for tender various blocks both offshore and onshore. The first bid round was a major success, in mid 1999, the second bid round being scheduled for the third quarter of year 2,000.
Blocks leased in the first bid round are now being explored by means of 2D and 3D seismic, and the first exploratory wells will be soon drilled.
This article presents a framework to perform an economic evaluation of oil & gas prospects, taking into account the risk factor. The Net Present Value of each block is first computed based upon an average value. Following that, Monte Carlo simulation is used to compute the downside risk. The inputs are determined by means of probability distributions. Reservoir parameters, capital and operating costs and oil prices are fed into the program, revealing the NPV sensitivity to each factor.
The problem is further structured by means of decision trees. The Expected Monetary Value, based upon perceived probabilities of success, is estimated, utility functions being used to account for risk aversion. The optimum level of participation in each prospect is determined, using the so- called Certainty Equivalent concept. Finally, the formation of an optimum portfolio is discussed, so that any oil company can establish its strategy in joint bids and farm ins.
Four hypothetical prospects are evaluated; with different levels of investment and risk profiles, namely, from higher probability of success to new frontier, lower probability of success. The correspondence with real life may be, respectively, the Campos Basin, where 70% of Brazilian oil production comes from, and basins like Pelotas, where there are no producing wells, with little seismic available.
The framework suggested in this work could be useful for any company that is currently involved with exploration activities. Additionally, it may be used for analyzing any investment with a certain degree of uncertainty or volatility.
Development of an Active Global Lessons Learned Database - LINK
Authors: Dewhirst Neil W. , Evans David C. , Chalfont Simon , Jobson Nigel 
Published: December 2007

Abstract
During 1999 BP Amoco developed an intranet based global lessons learned database for use by its well construction and operations teams. This tool, named LINK, was implemented in the +/-50 wells teams during 1Q 2000. There was business drive for the development of a tool that facilitated learning between teams without imposing any additional workload. Passive tools existed, but were mainly for use within single teams and were not easily accessible by anyone outside the team. The prize was in making it possible for wells teams globally to learn continuously and simultaneously.
LINK is designed to help teams deliver a significant, sustainable performance improvement in several ways: It provides each team with a lessons learned knowledge base and action tracking system to support continuous improvement.All users enter and access data in a consistent way, allowing all that is learned by BP Amoco wells teams to be easily accessible to everyone.It actively promotes connectivity between teams, ensuring that knowledge is disseminated throughout the community.
The active functionality ensures that teams are automatically made aware of what analogue teams have learned, both positive and negative. The system sends high value lessons to the relevant teams and communities of practice. The philosophy is that when engineers are made aware of what someone else has learned, if it is relevant to their operation and of high value, then they will act upon it locally, maximising the federal benefit of that knowledge.
LINK has become the global platform to disseminate high value learnings (including stuck pipe, well control, equipment failure, and HSE incident reports). Although LINK was developed for use in well operations, interest has been shown by other disciplines within the company. For example, Project Engineering, Petrophysics, & Geophysics are considering making use of the platform to facilitate similar collaborative learning behaviours resulting in improved performance in their areas.
Tracer Simulation to Improve the Reservoir Model in the Snorre Field
Authors: Ali E. , Chatzichristos C. , Aurdal T. , Muller J. 
Published: December 2007

Abstract
This paper presents the application of water tracer flow simulations as a means for better characterization of the Central Fault Block (CFB) reservoir in the Snorre field in North Sea. The simulations of the tracer flow were carried out using a numerical model, developed by the Institute for Energy Technology for modeling of tracer flow in porous media, coupled to CMG-STARS chemical/thermal simulator. The tracer data was first analyzed to establish reservoir continuity between three injectors and six producers in the fault block. Then, tracer flow simulation results were matched with measured tracer field data in order to improve the history match of the water cut in the reservoir model.
History matching of tracer production profiles is presented together with history matching of water cut before and after the consideration of tracers to highlight the improvement of the reservoir model.
Stability and Rheological Behavior of Aqueous Foams for Underbalanced Drilling
Authors: Rojas Y. , Kakadjian S. , Aponte A. , Márquez R. , Sánchez G. 
Published: December 2007

Abstract
This paper presents evaluations of stability and rheological behavior of aqueous foam formulations. The stability of these systems was evaluated by the Ross-Miles method, using half-life measurements, and was studied as a function of the type and concentration of surfactants, polymers and salts. The effect of contaminants such as crude oil is also examined. A capillary tube viscometer was used to perform the rheological studies. The effect of variables such as quality of the foam, pressure system, tube diameter and polymer type is shown. Results were corrected for wall slip effect and normalized by using equalized volume corrections.
Results indicated that the sensitivity of the foam to contamination with oil and salts depends on the chemistry of the foaming agent system and crude oil used. The rheological evaluations showed that the flow behavior is highly dependent on the foam quality for a given pressure, the chemistry of polymer and the tube diameter.
Real Real-Time Geosteering
Authors: Phillips Ian C. , Paulk Martin D. , Constant Anne 
Published: December 2007

AbstractThis paper is one of a series published during 2000 to coincide with the launch of an advanced drilling system known as "Anaconda". This drilling system utilises a manufactured carbon fibre composite tube in place of conventional steel drill pipe or coiled tubing. The composite tube incorporates wires built into the wall, making it possible to transmit all the available formation evaluation and drilling data to surface continuously and in real-time.This paper focuses on the impact of this real-time data availability on the ability to make real-time geosteering decisions. In particular we focus on:The uncertainty associated with wellbore planning at seismic resolution when compared with the fine resolution required for modelling log responses and planning well bore trajectories. The issues associated with planning well bores in geological space instead of geometrically are also explored. The issues relating to wellbore planning before the well is drilled and in particular the forward modelling of the anticipated log responses. The practical implications of having all the normal formation evaluation data available in real-time whilst drilling a well. These include handling large data volumes and the ability to reach well decisions in significantly shorter time frames. The software systems developed to deliver the ability to update the geophysical and geological interpretation in the time frame required to influence a well path. The technology which makes it possible to steer the drill string effectively in real-time as new data becomes available. The organisational implications for such real-time decision making – such as high-speed reinterpretations under operational time pressures. The business benefits that might derive from this real-time decision making capability – such as reduced numbers of geological sidetracks, ability to terminate a wellbore at the most appropriate time and maximising the productivity of the wellbore.