bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydraulic Limits for Drilling and Completing Long Horizontal Deepwater Wells
Authors: Martins A. L. , Aragão A. F. L. , Calderon A. , Leal R. A. F. , Magalhães J. V. M. , Silva R. A. 
Published: December 2007

Abstract
Long horizontal section wells are economical requirements for heavy oil fields in deepwater environments. This article discusses the operational limits for drilling and completing such kind of wells, considering the well extension and low fracture gradients encountered in deepwater reservoirs. Among the operational issues related to hydraulics, the following are critical: ECD restrictions, drilled cuttings transport, fluid substitution while running the screen and gravel pack placement (if this is the adopted sand control technique). A parametric study on the variables governing each of the three operations indicates that careful hydraulic design and detailed operational procedures can guarantee proper well construction.
Optimization of Hole Cleaning in Vertical Wells Using Foam
Authors: Li Yibing , Kuru Ergun 
Published: December 2007

Abstract
A mathematical model of the cuttings transport with foam in vertical wells has been developed and numerically solved recently.
In this study, based on the earlier solution, a numerical wellbore simulator has been developed and used for optimization of drilling hydraulic parameters (i.e. determine optimum values of foam flow rate, back pressure, foam quality, etc.) for effective cuttings transport with foam in vertical wells.
Effects of key drilling parameters (i.e. drilling rate, annular geometry, formation fluid influx, etc.) on the efficiency of cuttings transport have also been investigated.
A series of simplified hole cleaning charts have been developed which enable the optimum hole cleaning parameters to be determined at the rig site.
Continuous Improvement Philosophy Results in 50% Time Reduction to Sidetrack in the Shallow Oil Zone, Elk Hills Field
Authors: Starcher Mark , Shelander Jim , Presley Greg , Radford Steve 
Published: December 2007

Abstract
Continuous improvement measured in time savings required to sidetrack and redrill 133 shallow wells is documented. Time savings and a learning curve are related to decision making through a catalogue of sequential, applied techniques. Paralleling the evolution of applied techniques at the wellsite, bit and reamer technology evolves. Steer and ream while drilling tools (SRWD) evolve and make the sidetrack program viable. The confluence of geology, reservoir character as well as existing/new technology and management philosophy results in forecastable, positive changes. The incremental improvements produce a multi-year sidetrack program to successfully exploit the mature Elk Hills oil field.
Production Optimization of Gas Wells: Problem of Water Influx
Authors: Boussa Mohamed 
Published: December 2007

Abstract
Production - Pressure - PLT - RST – GHOST – CBL-Permeability - Porosity

Summary
The field of Hassi R' mel is a gas condensate reservoir with a superposition of three layers A - B - C having very good petrophysic characteristics and a rather significant oil rim in the Eastern and Southern peripheries.
Producing wells were drilled in the Northern part - Central - Southern with two lines of dry gas injection.
Production of water with high salinities disturbed the good production of the wells, which generated negative effects to the gas processing units.
It was necessary to decrease rate of flow of these wells to be able to decrease the volume of water, which generates a loss in the production of gas. In certain case it is necessary to close the well completely.
RST - PLT - GHOST were recorded on these wells to determine the origin of this water influx and a CBL was recorded to see the state of the cement of Liners.
Following the results of the operations carried out, a study was undertaken in order to see the method to be used for the optimization of these wells:
– Avoid placing a bridge plug for the layer C, because one will lose a good part of production of gas, since this level is more prolific than the other levels. – Isolate the places and perfos which produces water by a cement squeeze.
The purpose of this presentation is to show:
– Problems of water influx which penalizes the good performance of a well. – Solutions to adopt to improve the Index of productivity, by cement squeezing of the productive water zones.
A summary of the results on this operation will be analysed and shown in the form of tables and figures, which will enable us to draw a conclusion on the advantages and disadvantages from this operation.
Options and Special Considerations for Successful Deep-Water Well Testing of Heavy- and Low-Pour-Point Oils ? Case Histories
Authors: Wendler Curtis , Mansilla Cidar 
Published: December 2007

Proposal
Testing to evaluate the potential of a new well or field is a common practice in the oil and gas industry. When performing this task in a deep-water environment, the operator and service company must address the special needs of the testing environment, and when testing a heavy oil reservoir, the challenges are even further exacerbated. Special consideration must be given to the following issues:
High rig rates associated with deep-water operations will make job problems more costly. Producing heavy crude oil to surface, moving it through the surface production train, and finally, disposing of it in an environmentally acceptable manner Exposing the crude to an extended period of heat loss and low temperatures while it is in the landing string.
In order for the well test to be effective, all the above conditions must be fully understood and methodology employed that will reduce the chance that operational risks will occur.
This paper will discuss the successful testing of a heavy oil reservoir in deep water. A number of different ways to assist the production of heavy crude in the deep-water environment will be presented, and the relative merits and limitations of each will be considered. The discussion will provide an outline of the necessary additions to the surface production train and the use of chemicals and heat to ensure flow. Finally, the paper will consider what equipment is necessary to properly dispose of the produced fluid.
The testing methods discussed in this paper can be applied to heavy- and low-pour-point crudes in deep water. The equipment and methods can also be used in shallow water applications or on land. The case history data will illustrate:
Why particular methods and equipment were used and why others were rejected. The success of the methods selected to address the testing needs. What conditions are inherent when testing deepwater reservoirs in heavy oil, and what is required to nullify or reduce the impact from these conditions on testing operations. The lessons learned from the jobs. Improvements that could be made to further facilitate testing of heavy oil in a deep-water environment. How careful planning can overcome the testing problems in deep water for both low- and heavy-pour-point oils.
The information will show that employing proven methods and the proper equipment enables successful testing with reduced risk in difficult heavy- and low-pour-point reservoirs.
Innovative Reservoir Fluid Sampling Systems – Hamaca Project, Venezuela
Authors: Reddie David R. , Robertson Carlon R. 
Published: December 2007

AbstractThe Hamaca Project is a large resource base of Extra Heavy Crude Oil (7 to 9 API), located in the Faja oil belt, to the north of the Orinoco River, in Venezuela. Petrolera Ameriven (PA), an operating agent owned by Petroleos de Venezuela S.A., ConocoPhillips and ChevronTexaco, is developing the Hamaca extra-heavy crude oil project. Field start-up occurred in September 2001, with production from a few horizontal wells. Development drilling and field appraisal is ongoing, prior to start-up of the Upgrader and commercial production at about 190 Mbopd.Prior to start up of the field, a requirement existed for high quality samples of reservoir fluid to be obtained, for use in PVT and special core analyses, to aid in the prediction of reservoir performance. The general belief that recombination of oil and gas could not achieve a truly representative reservoir fluid sample led to the requirement to obtain reservoir fluid samples that had not experienced significant pressure depletion.In the development of the system employed, a rigorous review was made of available downhole sampling equipment. Instead of taking pressurized samples downhole, a rod driven progressive cavity pump (PCP) was used to pressurize the reservoir fluid and deliver it to surface, where samples were collected. The fluid pressure, at all levels above the pump, was greater than reservoir pressure, insuring high quality samples. This also required surface equipment to operate at higher than normal pressures, as compared to normal PCP operations.Every aspect of the system, and operating procedure, were examined and refined to minimize the possible pressure drop between the zone being sampled and the PCP intake. Using this system, single-phase fluid was captured at surface. This fluid, which had never experienced a significant pressure drop, was delivered to the lab, where PVT analysis confirmed that the formation fluid was at near saturated conditions, at reservoir pressure and temperature.In addition to about 4 liters, per zone, of single-phase sample for PVT analysis, approximately 45 liters were obtained from one zone for use in special core analysis studies, which would have been too expensive to obtain by conventional methods. The costs incurred in obtaining the large volumes of sample, by the single-phase pump to surface technique, were less than prior expenditures on more conventional downhole sampling operations, where small volumes of varying quality sample were obtained.
High Frequency Vibration Recovery Enhancement Technology in the Heavy Oil Fields of China
Authors: Guo Xiao , Du Zhimin , Li Guangquan , Shu Zhuangzhi 
Published: December 2007

Abstract
Interest in high frequency vibration recovery enhancement technology in the heavy oil fields of China is increasing. This paper describes its effect principle, the oil producing mechanisms, experiments and the pilot area applications. The technology is also compared with other types of well stimulation such as steam flooding, in-situ combustion, cyclic steam stimulation, chemical flooding and thin oil blending recovery used widely in the heavy oil reservoirs of China. We also made an attempt to simulate flow behavior of heavy oil reservoirs with vibration recovery by modifying an existed heavy oil simulator.
Mathematical Modeling of Steam Assisted Gravity Drainage
Authors: Akin Serhat 
Published: December 2007

Abstract
A mathematical model for gravity drainage in heavy-oil reservoirs and tar sands during steam injection in linear geometry is proposed. The mathematical model is based on the experimental observations that the steam zone shape is an inverted triangle with the vertex fixed at the bottom production well. Both temperature and asphaltene content dependence of viscosity of the drained heavy oil is considered. The developed model has been validated using experimental data presented in the literature. The heavy oil production rate conforms well to previously published data covering a wide range of heavy oils and sands for gravity drainage.
Modeling of Scale-Dependent Permeability Using Single-Well Micro-Models: Application to Hamaca Field, Venezuela
Authors: Waite M. , Johansen S. , Betancourt D. , Acharya U. 
Published: December 2007

Summary
In many reservoir-modeling projects, porosity-permeability relationships derived at the core plug measurement scale are applied to the reservoir model without properly taking into account the differences in scale between measurement and model grid block. Each grid bock in the reservoir model is assigned a permeability based on well log effective porosity and porosity-permeability correlations observed from core data, and then treated as a homogeneous volume with isotropic flow properties. This practice fails to account for the well-known phenomenon that in a stratified medium, effective permeability becomes more strongly anisotropic as volume-support increases from "quasi-point" core plug scale to scales which are larger than the heterogeneities which effect fluid flow.
This paper proposes a relatively simple and cost effective solution to the "scale mismatch" problem The quasi-point porosity-permeability relationship derived at the core-plug scale is more appropriately applied to single-well micro-models built from the integration of core and wire-line log data. The micro-models are then upscaled to produce porosity, vertical and horizontal permeability distributions and multivariate relationships that are consistent with the macro-scale reservoir model, while preserving the micro-scale flow characteristics. Upscaled porosity-permeability relationships are extracted and used to populate "effective" permeability into the macro-scale reservoir model, prior to flow simulation. The proposed method's application is demonstrated in the reservoir description and flow simulation of a giant extra-heavy oil field in Venezuela.
GeoMechanics Aspects of Multiple Fracturing of Horizontal and Vertical Wells
Authors: Soliman M. Y. , East Loyd , Adams David 
Published: December 2007

Abstract
Although unstimulated horizontal wells have been very successful in naturally fractured reservoirs and in reservoirs with gas or water coning problems, there are certain situations where fracturing a horizontal well may be a viable option. Because of the dependence of fracture orientation on well direction with respect to the stress field, the possibility of fracturing a horizontal well must be considered before the well is drilled. The appropriate contingency plans should be made to anticipate the possible low production from an unstimulated well. It should be remembered that fracturing a horizontal well may also dictate how the wellbore may be completed and/or oriented. Fracturing a horizontal well may take place in one of the following situations. Restricted vertical flow caused by low vertical permeability or the presence of shale streaksLow formation productivity due to low formation permeabilityThe presence of natural fractures in a direction different from that of induced fractures. Thus Induced fractures have a high chance of intercepting the natural fractures, orLow stress contrast between the pay zone and the surrounding layers. In this case, a large fracturing treatment of a vertical well would not be an acceptable option since the fracture would grow in height as well as length. Drilling a horizontal well and creating either several transverse or longitudinal fractures would allow rapid depletion of the reservoir through the fracture(s).
Although fundamentally similar to fracturing vertical wells, fracturing horizontal has its unique aspects that require very special attention to secure successful treatment. Differences between horizontal and vertical wells exist in areas of rock mechanics, reservoir engineering, and operational aspects. To start with, the basic rock mechanics aspects are examined.
Unlocking the Monterey Shale Potential at Elk Hills: A Case Study
Authors: Rowe Greg , Hurkmans Robert , Jones Norman 
Published: December 2007

Proposal
In an effort to improve oil production at Elk Hills, located in Kern County, California, successful new methods for acidizing both horizontal and vertical Monterey Shale wells were developed. During 1999 and 2000, 21 horizontal Shale wells were drilled with unacceptable production results, even though the petrophysical evaluation indicated the wells should have great flow potential.
The uncemented, slotted liners prevented the use of conventional stimulation techniques. Instead, the acid blend, placement, recovery, and flowback techniques using coiled tubing evolved and improved. Workover equipment optimization and utilization increased and time to market and operating expenses decreased. The results from acidizing horizontal wells increased oil production up to nine-fold.
Due to the successful large-volume hydrofluoric (HF) acid jobs on the horizontal Shale wells, many old vertical Shale wells were acidized using the same technique, increasing average well production by 110 barrels of oil per day (BOPD) and more than 500 MSCF/D. As a result of the diligent, combined team efforts of the operations personnel and the pumping service contractor, the total acidizing costs were reduced by U.S. $2,300,000. These costs were reduced through blending acid in the field, field-testing the oil for additives, lowering spent acid disposal costs, and mixing acid on the fly.
From Real Time Data to Production Optimization
Authors: Oberwinkler Christian , Stundner Michael 
Published: December 2007

Abstract
A new way of reservoir management is dawning at the horizon – intelligent reservoir management utilizing continuous data from intelligent wells and/or smart fields. Even though there are many different buzz words for this new technology, they all lead to the same – managing a reservoir in REAL TIME or close to REAL TIME. Real time usually means to react to an event as it happens or within a short time lag. In the petroleum industry real time is for sure different. This "short time lag" can be hours, days or even weeks, which of course depends highly on the objective itself.
Integrating real-time data into a reservoir management work flow and turn the data into value is a complex task. The bottle neck for the data flow right now is the transfer of the real time data - measured with a secondly and minutely time increment and stored on real time server – to the engineers’ desktops in a clean and timely useful fashion.
This paper will show ways how to provide a continuous (24/7) flow of clean data to the engineers’ desktop as a first step for the intelligent reservoir management. It will be shown that the implementation of a smart field rises or falls with the ability to provide the data to the knowledge worker – the petroleum engineer. Since the data is coming into the database, let’s say every hour or every other day, the engineer is not able to check this data for discrepancies. Therefore, intelligent reservoir management needs an alarm system to inform the engineers about any under performing or critical condition of a well or the reservoir itself.
Another important aspect is the integration of the standard petroleum engineering tools, like Decline Curve Analysis, Material Balance, IPR curves, Reservoir Simulation, etc., into this work process. Now an Inflow Performance Relationship Curve does not only get data every other month, but every other day. This gives the engineer completely new opportunities, e.g. monitoring the permeability impairment over time. Well tests are usually a snapshot in time, but with a continuous surveillance of the reservoir parameters, the development of, e.g., the skin can be followed over time and actions can be taken in time – predictive maintenance.
Neural Networks and Genetic Algorithms are other powerful tools in the real time environment, handling such a large amount of data. A Neural Network learns on the gathered data and detects their underlying relationships – the more data, the better. Afterwards, the Neural Networks can be used for predictions (predictive data mining) – for instance predicting sand production. This approach gives the engineer time to react, and prevents the equipment from harm.
This work and the methodology it implies, provides a straight forward way of integrating real time data into a reservoir management process and how to gain value from the information provided by a continuous data stream.
An LWD Formation Pressure Test Tool (DFT) Refined the Otter Field Development Strategy
Authors: Longis C. , Holm G. , Hill J. , Mitchell E. 
Published: December 2007

Abstract
Total, operating on behalf of Shell, ExxonMobil and Dana, is developing the Otter field in the North Sea. The development plan calls for three horizontal producers and two water injectors. Their location is critical to optimize production and reserves in this complexly faulted reservoir. The first well started producing in October 2002. The reservoir model assumed fault transmissibility and predicted that there would be a small but measurable depletion by the time the third well was drilled. When this well was entering the reservoir in January 2003, it was important to determine whether the reservoir drawdown matched the reservoir model. Formation pressure information was required as soon as possible, as this would have implications on the onward drilling program of well three and possibly on the relocation of one of the injectors. Since this well was penetrating the reservoir section sub-horizontally, any wireline formation tester would have to be run on drill pipe. An innovative technology, the Drilling Formation Tester (DFT), was utilized to gather the formation pressure data.
The DFT is a Logging While Drilling Tool (LWD) that performs formation pressure test using a dual packer configuration, a downhole pump, and a quartz gauge. It uses mud-pulse telemetry to transmit the downhole formation pressure data to the surface in real-time. Multiple tests can be performed to measure formation pressure and establish the formation fluid gradient. A Formation Evaluation LWD suite was run with the DFT. This allowed geosteering of the well into the optimal part of the reservoir and to investigate the reservoir pressure regime while drilling. This combination of LWD tools facilitated while drilling a comprehensive understanding of the reservoir, its fault compartments and pressure regime.
The real-time pressure data indicated that the well was located in a high permeability layer, confirmed the reservoir pressure model and facilitated the real-time decision-making process. The use of an LWD formation pressure tester was economic by saving an extra trip in the hole that would be required to acquire drill pipe conveyed wireline pressure data. It both added value through reduced operational risks as well as saving direct and indirect formation evaluation costs.
New Method of Representing Rock Properties Over Entire Bit Run Improves Computer Generated Bit Recommendations
Authors: Curry D. A. , Perry P. B. , Evans J. M. 
Published: December 2007

Abstract
In this paper, we demonstrate how the calculation of properties for an interval of the wellbore as a whole can support reasoned selection of drill bit features for that application by a rule-based expert system. We show how the use of measures that represent the rock's drilling properties over the entire bit run leads to significantly better bit design recommendations than can be made using just instantaneous foot-by-foot representations of drilling properties.
Risk Management Process for Ultra-deepwater Surface BOP Operations from a DP Drilling Rig
Authors: Taklo Tor , Magne Eric , Brander Graham 
Published: December 2007

Abstract
This paper describes the risk management process that was undertaken for the first surface BOP operation to be executed from a Dynamically Positioned drilling vessel in ultra deepwater (9474 ft WD). The paper briefly describes the case for change that presented itself to the operations drilling group and outlines the steps that were taken in order to ensure that the overall safety of the operation was equal to, or superior to, that of conventional subsea operations. A number of the key conclusions established from the risk management process are also presented.