bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of a Horizontal Flow Electrostatic Coalescer in Offshore Gulf of Mexico Service
Authors: Heatherly M. W. , Buchanan V. P. , Rawlins C. H. 
Published: December 2007

Abstract
An advanced design horizontal flow oil coalescer was installed on the Marathon-operated Ewing Bank 873-A (EW-873A) platform in early 1998. The coalescer's design has enabled it to significantly exceed design capacity while simplifying operations. Design features that aid in performance include: horizontal flow to minimize water carry-over with the bulk oil phase, a cyclonic inlet device to smooth the pipe-to-vessel transition and degas oil at inlet conditions, externally adjustable louvers to distribute oil flow evenly across the vessel, multiple externally adjustable electrostatic grids to vary field density and allow improved coalescence, and directed-flow matrix packing in the oil layer to enhance the removal of the coalesced water droplets created by the electrostatic field. Operation and maintenance improvements include: internal sampling points to quickly assess performance along the length of the coalescer, externally replaceable grid entrance bushings, and an interface draw-off line to remove chemical/solids laden pads.
This unit was installed as part of a platform upgrade and operates parallel to a vertical upflow coalescer. The existing upflow coalescer is frequently unable to achieve 1.0 % BS&W in oil effluent at lower than design rates, while the horizontal flow electrostatic coalescer consistently provides &lt;0.4% BS&W at 120% design capacity (61,000 BOPD versus 50,000 BOPD). This paper will detail horizontal flow coalescer design, with an emphasis on internal components, and provide highlights from its four-year operating history in a side-byside comparison to a conventional upflow coalescer.
Planning and Execution of Long Horizontal Gravel Packs in Extended Reach Wells
Authors: Corbett Gary , Winton Suzanne 
Published: December 2007

Abstract
Horizontal openhole gravel packs provide excellent sand control, high productivity and sustained well life. This paper describes the application of openhole horizontal gravel packing to extended reach wells in a North Sea field. Openhole horizontal gravel packed sections in this field range from 1,200 ft to almost 7,000 ft in length. The key to successfully gravel packing these ultra-long horizontal wells is proper planning and field execution. The initial planning process requires identification of the risk factors associated with horizontal gravel packing. These risk factors are discussed in the paper, as well as techniques available to reduce risk. In addition, this paper describes the extensive well planning process required to design and execute long horizontal gravel packs. Issues such as well path selection, workstring selection, drill-in fluids, well displacement, service tool configurations, rig-site logistics and contingency planning are discussed in detail. Finally, a summary of the gravel packing results achieved to date in the subject North Sea field is presented.
Water Control in Oil Wells With Downhole Oil-Free Water Drainage and Disposal
Authors: Inikori Solomon O. , Wojtanowicz Andrew K. , Siddiqi Sarmad S. 
Published: December 2007

Abstract
In bottom water drive oil reservoirs, the use of dual-completed wells with water drainage-dubbed: Downhole Water Sink (DWS) technology - has proved to control water coning, increase oil production rate and total recovery factor. Also, in field trials, the technology demonstrated sustainable production of oil-free drainage water. The ability to produce oil-free water makes DWS extremely attractive in offshore operations as no water processing is needed prior to overboard discharge. In land operations, oil-free water may be injected into the same well below the drainage completion or lifted to the surface and disposed into injection wells without processing.
Field tests and our studies have also showed that sustainable drainage of oil-free water becomes somewhat difficult as the two completions (top and bottom) may receive co-mingled inflows of the two fluids. The phenomenon indicates the existence of transition zone (with mobile oil and water) much larger than that explained by the capillary pressure effect. This paper presents the results of a study - using numerical simulator and a pie-shaped physical model-aimed at understanding the change of transition zone around producing wells with and without DWS.
The results show that, in conventional wells with water coning, the transition zone is small and constant away from the well but enlarges towards the wellbore. This transition zone enlargement effect occurs in conventional wells due to diffusion resulting from pressure distribution around the well. For DWS wells, however, the effect is not only more pronounced but it also alters the IPW plots – a basic tool for design. There is a commingled inflow envelope in addition to the envelope of segregated inflow.
Based on the above understanding, the paper shows how to design operational limits for DWS wells to maximize oil production from the top completion and maintain oil-free water drainage from the bottom completion.
The Development and Testing of a Garaged Open Hole Logging System for High Angle Wells and Bad Hole Conditions
Authors: Elkington P. A. S. , Spencer M. C. , Spratt D. L. 
Published: December 2007

Abstract
A mechanism for conveying logging tools inside drill pipe has been developed that reduces the risk and cost of acquiring open hole formation evaluation data in high angle wells and bad hole conditions. The measurement string is garaged inside drill pipe where it is protected while running-in, being released into open hole close to final depth. Wireline tools are used for data quality reasons, but the wireline has been eliminated, giving time, well access and well control advantages relative to wireline pipe conveyed logging. Over shallow, long horizontal intervals the time savings are substantial because wireline re-latching is eliminated, and pipe is run-in at tripping speed. The ability to circulate over and around the tools means that logging and hole cleaning trips can be combined to give further time reductions. Cost and data quality advantages have been demonstrated relative to logging-while-drilling in wells where real-time formation evaluation data is not used to guide the drilling process.
A 1.4-Km test loop constructed during the development phase proved the tool deployment sequence can be controlled and monitored using mud pressure. It enabled the design to be refined before being run in real well environments, and resulted in the development of novel payload delivery seals - a key component in the system.
Using the new method, formation evaluation data has been acquired in horizontal wells that would not have been logged previously for reasons of accessibility and/or cost. Knowledge gained from the interpretation of these data sets has influenced the installation of completions in new wellbores, and guided remedial action in others.
Developing New Fields Using Probabilistic Reservoir Forecasting
Authors: Kabir C. S. , Chawathé A. , Jenkins S. D. , Olayomi A. J. , Aigbe C. , Faparusi D. B. 
Published: December 2007

Abstract
Limited and uncertain geologic and engineering data at the onset of any new field development are the bane of reservoir characterization and simulation. The problem stems from the uncertainty in various model-input variables, such as reservoir connectivity, fluid viscosity, and endpoint saturations, to name a few. Given this scenario, an ad-hoc, one-factor-at-a-time approach to earth and flow-simulation modeling cannot possibly yield unbiased information for making objective business decisions.
This study presents three field cases where both engineering and earth model variables were varied in a systematic way to assess reservoir performance using the Experimental Design (ED) approach.
Results of the field cases show that well requirements, both producers and injectors, turned out to be fewer than those thought initially. Equally important, one case study showed that laboratory measurements could minimize uncertainty surrounding oil viscosity and endpoint saturations. At the same time, we learned the preferred horizontal well orientation was marginally superior to vertical wells, in light of high reservoir anisotropy. In another case, stratigraphy, gas-oil contact, and aquifer strength became the primary variables for the full-factorial design, after the initial screening. Here, we proved that the project could proceed because it met the minimum reserves criterion. Perhaps most important, all studies showed how to obtain unbiased information in far fewer flow-simulation runs than one would do using an ad-hoc approach.
Thermal Behavior During Restart of Ultradeepwater Flowlines
Authors: Golczynski T. S. , Niesen V. G. 
Published: December 2007

Abstract
For subsea tiebacks in ultradeepwater, restarting from shut-in conditions can pose significant flow assurance issues. For both planned and unplanned shutdowns, live fluids from the wellbore will come into contact with a cold flowline and can form hydrates during restart since the conditions at the mudline are often well within the hydrate formation region. As the water depth increases, the potential for even higher shut-in pressures exists, exacerbating the probability of hydrate formation.
The achievable restart flowrates are directly related to the available inhibitor rates. Ultradeepwater systems often require high hydrate inhibitor (i.e. methanol) dosage rates to protect the flowline from hydrate formation. In general, the temperature warm-up trend is exponential and is a function of the amount of energy input into the system. If the restart flowrate is too low, limited by inhibitor availability, the temperature may slowly approach a condition at which the system is free from hydrate formation and ultimately require a significant inhibitor volume. For these low restart flowrates, the time to reach conditions above the hydrate formation region can be very significant or the flowline may never warm up above hydrate conditions. At high restart flowrates, the flowline warms up quickly, but the inhibitor delivery rates are high, often significantly higher than those required for a similar development in shallow water. There is a trade-off between inhibitor deliverability (line size) and consumption (storage) that must be accounted for at the design stage of a project when considering how to restart the system.
Operational procedures such as preheating the flowline with dead (de-gassed/de-watered) crude oil to warm up the pipe walls before restarting the wells have been suggested as a means of expediting the overall flowline warm-up. Preheating the pipe walls maintains the thermal energy in the production fluid and reduces temperature losses associated with the fluid warming up the pipe walls. The effectiveness of this technique, while potentially reducing the warm-up time, may again be limited by the allowable restart flowrates.
Wellbore Heating To Prevent Liquid Loading
Authors: Pigott Mikell Jason , Parker Mike Henry , Mazzanti Daryl Vincente , Dalrymple Larry Verl , Cox Don Crafton , Coyle Robert Aden 
Published: December 2007

Abstract
The Pettit formation in Carthage Field is predominately a gas reservoir. At reservoir pressure and temperature, no free liquids are produced. However, water and condensate will drop out of the gas stream as the gas cools on the path to the surface. When the production rate declines below the critical velocity these fluids can accumulate and cause the well to load up and eventually cease flowing.
Heating the wellbore to reservoir conditions is a new method of eliminating fluid condensation in the wellbore. This paper discusses the first successful application of wellbore heating to prevent fluid condensation and eliminate liquid loading. This application is in the Carthage Field.
Managing Exploration Performance: A Case Study For The Use Of The Internet To Enable Real Time Portfolio Management
Authors: Hewitt Bill , Wilson Hamish , Roberts Spencer J. , Fullerton Daryl 
Published: December 2007

Abstract
This paper describes how BP designed and set up a web-based system to manage the performance of their Near Field Exploration programme. The programme is characterised by a dynamic high volume of activity, as compared with more traditional exploration. Therefore capital must be managed and moved between business units throughout the year to continuously maximise production delivery for a given level of exploration spend.
The traditional methods of managing exploration, with annual capital allocation and ‘in-year’ quality assurance were not appropriate. The Near Field Group evolved a process based around quarterly meetings to review performance and agree the next quarter's activity. In effect, the group's goal was to manage the near field portfolio on a real time basis to continuously optimise performance. To achieve this goal accurate data on the individual investment options became an essential requirement.
The Internet provides a technological solution to support this process. BP, with external assistance, built a web-based system for collecting and managing individual investment options. A ‘Rapid Build’ approach using ColdFusion and other Internet technologies was used to develop and deploy a ‘live’ system within four months. The system is database driven utilising a web-interface to gather and display data through a series of forms and summary cards. It also offers the ability to display real time data through a series of customisable reports and dynamically generated graphs. The application resides on BP's intranet and forms a networking tool for all the business units in the Near Field Group. The primary function of the system is a commercial prospect database, which is regularly updated through the web at each local office. The database contains details of current and future prospects and also manages data on completed projects (both success and failure) in order to monitor their production delivery through time. This allows continual refinement of the groups technical prediction accuracy.
The system has been implemented for over two years and the ability to dynamically manage a portfolio on a real time basis has proved its worth; the Near Field Exploration programme is a great success. Many other features to facilitate collaboration have been incorporated. A significant benefit is the ability to collectively make investment decisions without meeting face to face. In today's business climate the ability to make faster more informed decisions with confidence is essential.
An Integrated Approach To Optimizing a Large Asset
Authors: El-Banbi Ahmed H. , Fathy Khaled , Morsy Samir Y. , Aly Ahmed M. , Alam Alaa , Fattah Mohamed A. 
Published: December 2007

Abstract
A major integrated study was performed to optimize the development of a complex field and to find opportunities to increase oil production. The field is composed of eight stacked reservoirs. The field was developed with more than 160 wells and has been producing since 1960. A pilot gas injection project was installed in the early 1990's. Despite the large number of wells and long production history, only 10% of the OOIP was recovered to date. An integrated approach was used to construct a dynamic model for the field and couple it to economical calculations. The model was used to optimize the performance of the field, increase recovery factor, and accelerate production. Unique to this paper is the procedure of history matching large amounts of data and long history. A relatively large model was constructed and then was broken down to seven models. The history match was attempted for each model separately. The seven parts of the field were then combined and the history match was refined. This history matching procedure resulted in significant time savings in the study and allowed the study team to dedicate most of their time to field optimization and to understanding the reservoir behavior.
Exceptional Proppant Flowback Control for the Most Extreme Well Environments: The Shape of Things to Come
Authors: Stephenson Christopher , Ward Brian , Taylor David Milton , Brannon Harold , Rickards A. 
Published: December 2007

Abstract
Proppant flowback within deep hot wells and/or highly productive wells is a major problem in the oil and gas industry. Under these extreme conditions, many of the current products and processes to control flowback often fail. As such, improved or alternative technology and procedures are constantly being sought. One such technology is the development of deformable proppants.
Material and structural improvement to a deformable proppant has allowed laboratory test conditions to be extended to higher temperature, closure stress and flowrate. As a result of this fine tuning, exceptional proppant flowback control has been obtained. Testing of this new deformable proppant, blended with typical fracturing proppant, has shown 50 fold increases in flowrate and 100 fold increases in pressure drop are attainable without pack failure, while still maintaining fracture conductivity.
Furthermore, this deformable proppant has been applied in wells where current technology would either fail or have serious drawbacks. In two primarily gas producing reservoirs, the addition of this deformable proppant to proppant packs placed during fracturing treatments, has been observed to very effectively control proppant flowback under conditions of high bottom hole temperature, high fracture closure stress and high production regimes. In order to facilitate field application, new addition and monitoring procedures were developed to accomplish these successful fracturing operations. The developmental testing, successful application and well performance all indicates significant improvement in proppant pack integrity.
An Improved Placement Technique for Resin-Coated Gravel in Through-Tubing Gravel Packing
Authors: Berg Erik , Haugum Ola , Reinertsen Trond , Harestad Kristian 
Published: December 2007

Abstract
Through tubing gravel packing in wells with ID restrictions inside the production tubing is a challenge related to installation of down-hole equipment and placement of gravel in perforations and behind casing.
In the North Sea conventional gravel packing has been the preferred method with regards to remedial sand control, but in wells with ID restrictions this can lead to a reduced accessibility and flow impairment in the producing well. Use of resin coated gravel without pre-installed screens is also utilised as an alternative method but has been limited to short perforation intervals due to insufficient placement techniques.
In 1999 a high rate oil producing well at the Snorre field in the North Sea was gravel packed with 16/30 mesh resin coated proppants utilising a new tool for improved placement of proppants behind the casing and inside the perforations.
The well was completed with a 7" liner, cemented and perforated, and a 5.5" production tubing. The smallest ID inside the production tubing was a "no go nipple" of 3,75". An interval of 34,5 m containing three perforated zones of total 12,5 m was gravel packed in one operation. The placement tool which consists of 7 glasfiber tubes designed as an internal shunt tube system, allows gravel slurry to be pumped past possible sand bridges forming in long intervals. The tool was split in three lengths of approximately 14 m each and placed in the well on wireline. The gravel pack operation was performed through coil tubing in squeeze mode with pre- heated carrier-fluid to improve the curing of the resin. A total of 10 ton. proppants was pumped during the operation and 7,6 ton. of proppant was placed behind the casing and in the perforations, giving a gravel pack efficiency of 3.9 ft3/ft of perforations. After curing, excess proppants and the placement tool was milled out with coil tubing.
Capillary Shockwave Front Blind Imaging of Reservoir Limits: A Case Study
Authors: Goldsberry Fred L. , Anderegg Kevin C. 
Published: December 2007

Abstract
Reservoir boundary information is gleaned from a steady-flowrate-drawdown test and/or a subsequent buildup following the steady flow period. Singularities are observed to be present in virtually all transient pressure data that can provide direct information about the limits around a well. Multiple limits can be detected discretely and described by distance from the well and angular shape at the point of contact. The input information required is pressure data acquired while flowing on a fixed choke, petrophysical properties from cores and electric logs, and fluid production rates and compositions during the flow period.(2)
Reservoir limits can be assembled into an energy equivalent image based upon cone of influence energy growth behind a bounding initiating capillary pressure shockwave front. The resulting image can then be compared with a seismic data based map or a geologic map. Volume integrals for gas inplace can provide an early physical measurement for reserve accounting purposes.(4,5,6,8)
A variety of boundary contact shapes were assembled into a "blind" energy map that was later confirmed by seismic imaging. A direct overlay comparison of the "blind" energy image and a 3D seismic map is presented. The limit information will be compared with the seismic image to confirm it point by point.
This new transient pressure analysis method is based upon a real capillary network growing from the well bore. Flow into the well bore is restricted to radial flow and confined to the real capillary flow paths by initial capillary pressure.(2) The cone of influence is bounded by an associated capillary shockwave front that restricts its growth. The bounding initiating capillary pressure shockwave front is the physical phenomenon that exists at the radius of investigation(1,7,10) The capillary networks give rise to secondary pressure singularities when a boundary is encountered. The method extends traditional analysis to the realm of wave mechanics(8,9,11) and allows direct data processing. The solution is based upon an energy model that solves for boundary geometry directly from flow and buildup data without the process of traditional iterative history matching. The boundary contacts can then be assembled into an image of the reservoir based upon relative disposition of individual limit contact.