bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Real-Time Wellbore Stability Monitoring on a Deepwater ERD Well
Authors: Greenwood J. A. , Brehm A. , van Oort E. , Algu D. R. , Volokitin Y. E. 
Published: December 2007

Abstract
Good geomechanical modeling can provide valuable information for the efficient design and drilling of wellbores. Incorporating real-time wellbore stability monitoring during drilling can reduce the associated risks, especially for deepwater extended-reach wells. This paper presents the preparation, delivery, and outcome of the field trial for a real-time wellbore stability monitoring service delivered at Shell Exploration and Production Company's office in New Orleans.
Three key objectives were set for the field trial: (1) to develop the processes to incorporate real-time wellbore stability into the current operations center monitoring provision, (2) to provide frequent updates of the wellbore stability model using a geomechanical modeling technique that was independent of the operator's own methods, and (3) to monitor and verify the geomechanical model based upon the drilling experience enabling proactive decision making during drilling. For the operator's asset team, the main objective was to reduce trouble time and make execution of the well successful.
Ram Powell VK 913 A-9 well was chosen as a candidate for the field trial. The Ram Powell tension-leg platform is located in 3200 feet of water in the Eastern Gulf of Mexico. A-9 was planned as an extended-reach exploration and would have the highest angle at the shallowest depth in the field. A geomechanical model for the prospect had already been created using the operator's own well-established methodology. This pre-drill model was transferred into the service company's software, and the real-time model was calibrated to generate as close to the same output as possible. After verifying the real-time model using the drilling experience on the closest offset wells, the 24 hr real-time stability monitoring commenced. The real-time geomechanical monitoring encompassed pore pressure prediction, rock property calculations from formation evaluation tools, wellbore trajectory updates, and the use of surface and downhole drilling data to verify the geomechanical model.
Integration of the real-time wellbore stability monitoring contributed to the successful drilling and casing of this deepwater extended-reach well. The trial resulted in a greater understanding of the geomechanics of the field. The trial also resulted in a better understanding of procedures for maximizing the value of real-time data and of associated monitoring services, services that will be incorporated in future Shell E&P wells.
DDV Reduces Time to Round-Trip Drillstring by Three Days, Saving £400,000
Authors: Sutherland Iain , Grayson Brian 
Published: December 2007

Abstract
Fluid invasion of a reservoir during conventional overbalanced drilling operations can cause considerable formation damage. Increased awareness of the degree of damage possible has raised interest in the benefits that underbalanced drilling (UBD) offers. UBD techniques are not necessarily suitable for all reservoirs but can provide significant benefits in certain instances.
During UBD operations, the formation is allowed to flow; so a surface pressure is ever present in the annulus. A rotating control head is used to control the pressure. As tripping begins and the pipe is stripped through the wellhead, the pressure must be managed to prevent a pipe-light situation.
Killing the well to control it and allow for conventional tripping of drillstring is not always a viable solution; and, until recently, the only accepted method for tripping drillstring in a constant underbalanced state has been snubbing, which can have operational and economic drawbacks in some situations. This paper describes how implementation of the downhole deployment valve (DDV) in a Southern North Sea drilling program reduced overall program costs, set multiple records, and demonstrated successful integration of a new technology into one of the most critical underbalanced operations in the world.
Mooring and Riser Management In Ultra-Deep Water and Beyond
Authors: Pelley Darrel K. , Steddum Riddle E. , Westlake Andrew S. 
Published: December 2007

Abstract
In recent years, offshore oil and gas exploration has rapidly advanced to record water depths that were beyond conception 20 years ago, with the 10,000-ft water depth barrier hurdled in 2003 in the US Gulf of Mexico. Drilling equipment design and capability to achieve this record has simply grown to meet increased capacity requirements.
This paper outlines the mooring and drilling riser management challenges that will need to be realized in 10,000 feet of water and beyond. By defining the boundary conditions for moored and dynamically-positioned scenarios in future record water depths, the challenges to the design and operation of mooring and riser systems can be explored, including component design issues, deployment techniques and system management in adverse environmental conditions. Previous work undertaken on this subject by Transocean shows that the capabilities used to break the 10,000-ft barrier will require yet another step-change to drill in water depths of 12,000-ft (DP) or 10,000-ft (Moored) with conventional subsea well control equipment and marine drilling risers.
Two scenarios are presented, one each for moored and dynamically positioned vessels to demonstrate the requirements that require special consideration for successful operation and management of mooring and marine drilling risers.
Reducing Risk and Cost in Diverse Well Construction Applications: Eccentric Device Drills Concentric Hole and Offers a Viable Alternative to Underreamers
Authors: Rasheed Wajid , Trujillo Jorge , van Oel Ruben , Anderson Mark , McDonald Scott , Shale Les 
Published: December 2007

Abstract
Increasingly, operators seek to underream. Whether driven by cementing tolerances, ECD improvements, pore pressure fracture gradients, production increases, swelling shales/salts or setting sand screens, underreaming is sought after at all stages of field development.
To date, the industry has a common perception that concentricity can only be delivered through concentric cutting mechanisms. This paper proves otherwise. The performance, risks and suitability of an eccentric underreaming device are compared with concentric underreamers. Usage in over 100 well sections is tabulated and reviewed to verify the device drills concentric hole in differing formations and applications.
Pilot bit and underreamer cutter characteristics are matched for directional control, durability and hole quality. Specific attention is paid to N Sea & GOM run history covering usage with push and point-the-bit rotary steerables. In exploratory, deepwater or complex well paths, the device is placed above a 3-D rotary steerable and full logging suite. Here the problem of leaving pilot gauge rathole is also addressed. In enhanced RPM, motor directional applications it is placed as nearbit.
Computational fluid dynamics, nozzle and PDC cutter layouts are also discussed with regard to optimizing cuttings evacuation, hole cleaning, BHA stability and ROP.
In conclusion, 20 different well construction activities are presented and used as a benchmark for the evaluation of the risks and suitability of the device as compared with concentric underreamers.
Mature Field Benefits from Application of High-End Technology
Authors: Bone Glenn , Janwadkar Sandeep , John Wolfgang , Isbell Matt 
Published: December 2007

Abstract
Economical development of deep oil and gas wells in the Marlow field in Southern Oklahoma requires efficiently drilling a complex geological structure with faulted and highly dipping formations. Operators typically employ conventional motor directional systems to keep inclination to a minimum in the 8-3/4" vertical hole section. While this type of bottom hole assembly (BHA) has improved directional control, it still leads to unacceptable angle building tendencies/dogleg severity and poor vertical hole quality resulting in additional directional issues in subsequent hole sections. In addition, the conventional directional assembly increases well costs due to multiple deviation correction runs with different BHA configurations resulting in more flat time, lower cumulative bit penetration rate, and more bits/runs per section.
To address these issues, the service company studied drilling performance, mud logs and wireline data from offset wells. The resulting analysis detailed the key problems and led the operator to set new objectives for the 8-3/4" vertical hole section of achieving the highest possible rate of penetration (ROP) while maintaining a near-vertical wellbore. An implementation strategy was outlined that had two main components including a sophisticated vertical drilling system (VDS) with a new polycrystalline diamond compact (PDC) bit technology.
This approach has been utilized to drill the 8-3/4" hole section on two wells with the following results: Reduced inclination from 22º to 1.5º (VDS) and reduced dogleg severity (DLS) from 4º/100ft to just 1º/100ft (VDS). The new system has also reduced torque/drag and delivered a smooth quality wellbore and totally eliminated costly correction runs. The increased wellbore quality has allowed the operator to log, then set 5 ½" casing without incident. The operator has experienced increased performance when kicking off below a section drilled with the new BHA (VDS/bit) improving directional control and aiding geosteering to the target reservoir.
Bromine-Based Biocides for Effective Microbiological Control in the Oil Field
Authors: Carpenter J. F. , Nalepa C. J. 
Published: December 2007

Abstract
Maintaining biological control of oilfield systems is critical. Microorganisms can cause well souring, equipment plugging, loss of formation injectivity, destruction of essential additives, and MIC (microbially induced corrosion). To minimize these problems, biocides are often used. Systems commonly treated with biocides include water injection, fracturing fluids, and hydrostatic test waters.
In this paper we review the family of bromine-based biocides and discuss the basics of their chemistries and properties. We focus on a new stabilized bromine chloridebased biocide that has been demonstrated in a slickwater fracturing fluid field trial. Here, excellent microbiological control was maintained cost-effectively with relatively low biocide residuals.
A Chemical "Trigger" Useful for Oilfield Applications
Authors: Todd B. , Funkhouser G. P. , Frost K. 
Published: December 2007

Abstract
A number of oilfield operations are controlled by use of delayed chemical reactions. Breakers for fracturing and gravel packing fluids, filter-cake cleanup treatments in horizontal wellbores, and retarded acidizing are just a few examples. However, these reactions are best described as slow or gradual reactions and not truly delayed chemical reactions. The gradual degradation of a fracturing-fluid viscosity or a drill-in fluid filter cake can take place over a matter of hours. But even greater benefit could be realized in completion operations if events could be delayed for days and triggered at the desired time.
The delayed acid-releasing system, which is based on orthoesters in combination with alkaline inhibitors, can remain seemingly inactive for days before becoming strongly activated. The acid that is generated can then be used to break polymers, remove filter cakes, or activate other chemical processes.
The paper describes the chemical principle on which the system is based, and discusses a number of applications that could be improved and economized with the long-term delay and scheduling flexibility offered by the chemical-trigger system.
Also presented are the current operating envelope and plans for future widening of the temperature and delay-time ranges. A number of new testing procedures used to prove the system's unique properties are reviewed in the paper.
Efficient History Matching Using a Multiscale Technique
Authors: Aanonsen S. I. 
Published: December 2007

Abstract
It is demonstrated that a method for multiscale history-matching can be used to improve efficiency and/or quality of the solution when achieving a fine-scale match as compared to history-matching directly on the fine scale. Starting from a given fine-scale realization, coarser models are generated using a global upscaling technique where the coarse models are "history-matched" with respect to the solution at the fine scale. Conditioning to dynamic data is done by history-matching a coarse model, and this model is then successively refined using a combination of downscaling and history matching until a model matching dynamic data is obtained at the finest scale. The advantage of this procedure is that the large-scale corrections are obtained using fast models, which combined with proper downscaling procedures provide a better initial model for the final adjustment on the fine scale. The coarse-scale history-matching also provides a regularization of the fine-scale match making the process less dependent on a correct prior model. With the proposed methodology, a series of models of different degree of complexity, all being consistent with both static and dynamic data, may be generated without additional cost. Effects of using á priori information and different initial downscaling techniques, such as sampling or block kriging with sequential Gaussian simulation are investigated using 2 synthetic reservoir models.
"Surface BOP, Slim Rise or Conventional 21-Inch Riser – What is the Best Concept to Use"
Authors: Childers Mark 
Published: December 2007

Abstract
There are four (4) ultra deepwater (over 5,000 ft) subsea drilling systems available to the industry. The Conventional 21-inch riser/18 ¾ inch BOP stack used with 5th Generation MODUs, Surface BOP (SBOP) located directly under the rotary with high pressure casing riser to the seafloor using a 2nd to 5th Generation Semi MODU, a version of the SBOP with a Subsea Disconnect System (SDS) at the seafloor, and the Slim Riser Concept using a 16-inch standard riser with a 3rd or 4th Generation Semi MODU and 18 ¾ inch BOP. The SBOP with the SDS consists of two hydraulic connectors and two shear rams. Slim hole technology is an integral part of SBOP and Slim Riser concepts.
The SBOP concept is most economical and successful when a large number of wells (15 or more) are drilled such to payout the CAPEX for MODU modifications and other equipment. In addition, the wells should be expendable, normal pressure, less than 3 strings of casing below the BOP, slim hole drilling technology is acceptable, and used in a benign environment5. If the latter requirements are present and shallow gas or well control is an issue and/or the location is not in a benign environment, then the SBOP with a SDS is worth considering. The Slim Riser Concept is best for wells that are to be kept for production or reentry, are more complicated and require more time and technology to drill, are in more severe environments, disconnection of the riser is more likely, there are a reasonable number of wells (9 to 12 months of contract work) for payout of the MODU modifications and equipment, and/or the Operator is not comfortable with the SBOP concepts. Cost to do the modifications to the MODU, schedule (rig and well), well type and anticipated problems, operator and regulator acceptance of a concept, and rig type availability are among major factors in selecting a concept. The primary incentive for using the SBOP without SDS and/or the Slim Riser Concept is the ability to use a much lower price MODU day rate vs. the Conventional 21-inch concept. The pros and cons, advantages and disadvantages, and other factors in relationship to the 4 concepts mean that one concept is not the "best" solution for every well program. Rigorous analysis and evaluation of all factors are key in selecting the "best" concept for the well (s) or project under consideration such to derive the most cost effective and low risk approach.
"Clean Up" of Oil Zones after a Gel Treatment
Authors: Seright R. S. 
Published: December 2007

Abstract
Because polymers and gels can reduce permeability to water much more than that to oil, an unfavorable displacement (high mobility ratio) usually occurs in oil zones when wells are returned to production after bull-headed gel treatments. Since oil displacement through gel is unfavorable, the permeability to oil requires a large throughput to stabilize. Consequently, oil zones often exhibit a significant "cleanup time" after field applications of gel treatments. The oil and water throughput requirements for stabilization of permeabilities were studied for a relatively "strong" pore-filling Cr(III)-acetate-HPAM gel and for a "weak" adsorbing polymer. As oil throughput increased from 1 to 100 PV, permeability to oil gradually increased by factors from 5 to 10 for cores treated with the Cr(III)-acetate-HPAM gel and from 2 to 3 for cores treated with the adsorbing polymer. In contrast, after treatment with gel, permeability to water stabilized rapidly and remained very low for over six months. An explanation is provided.
A simple mobility-ratio model was used to predict cleanup times for both fractured and unfractured wells after a gel treatment. The time to restore productivity to a gel-treated oil zone (1) was similar for radial versus linear flow, (2) varied with the cube of distance of gel penetration, (3) varied inversely with pressure drawdown, (4) varied inversely with the kw at Sor in the gel-treated region, and (5) was not sensitive to the final ko at Swr. Although ko at Swr (after gel placement) had no effect on the cleanup time, it strongly affected how much of the original oil productivity was ultimately regained. Earlier work demonstrated that an acceptable gel or polymer placement can be achieved by unrestricted injection of gelants during linear flow (e.g., vertically fractured wells). However, in radial flow through matrix (e.g., unfractured wells), hydrocarbon productive zones must be protected during gelant or polymer placement. These conclusions were confirmed by our new results for both the Cr(III)-acetate-HPAM gel and the adsorbing polymer.
Modeling of the Asphaltene Precipitation in Bangestan Reservoir of Kupal Field
Authors: Jamshidnezhad M. 
Published: December 2007

Abstract
Modeling of asphaltene precipitation in Bangestan reservoir of Kupal field in southwest of Iran is the purpose of this study. The modeling technique based on the representation of the precipitated asphaltene as a pure dense phase and division of the heaviest component in the oil into non-precipitating and precipitating components. A set of dummy experimental data was used to tune an equation of state based model that represents the asphaltene as pure component solid. Results of the work show that the chosen model could accurately represent the behavior of the fluids of this reservoir.
Experiences in NISOC fields prove that when solid precipitation is about 10 % (w/w), the problem of asphaltene will serious. Based on this study, we concluded that at about 5300 psia the amount of solid is 10 %. Therefore, when pressure in the Bangestan reservoir of Kupal field approach to this critical pressure (5300 psia) gas should be injected. Now, NISOC reservoir-engineering department are providing a plan for gas injection in order to increasing pressure in this reservoir.
The Bangestan reservoir of Kupal field started producing in 1989 under primary depletion. The reservoir has undersaturated oil with the production mechanisms being fluid and rock expansion along with gravity drainage.
Development of Green Chemicals For Cleaning Operations in Platforms Decommissioning
Authors: Dalmazzone C. , Carrausse M. , Tabacchi G. , Mouret A. , Noïk C. 
Published: December 2007

Proposal
Chemicals in decommissioning activities are not considered as an important challenge as far as all the products used are selected from the PLONOR list. Consequently, an important work has to be done to obtain safe and efficient products to facilitate cleaning operations and to limit the volumes of polluted water. The main constraint is to propose detergent formulations that are non-toxic and biodegradable. Furthermore, formulations must be compatible with cold seawater and must allow a fast separation of hydrocarbons from the aqueous phase. The objective of this paper is to present the development of a strict methodology for cleaning products selection. The innovative aspect of this methodology is firstly based on a pre-selection of safe molecules coming from a green chemistry, such as alkylpolyglycosides for instance. In a second step, formulations based on mixtures of several efficient and safe active matters are tested on different supports (glass, steel, cement…) in order to assess their detergent efficiency against several types of crude oils and weathered crude oils, the kinetics of separation of the formed emulsion, the formation of foam and the quality of the separated aqueous phase. Ecotoxicity tests on molecules are performed according to OSPARCOM guidelines (aquatic toxicity, biodegradation, and bioaccumulation). Complementary toxicity tests are also carried out on the separated water after cleaning, in order to estimate the toxicity of the aqueous phase to be discharged. The last phase of the methodology consists in a validation of formulations performances in large scale experiments performed in CEDRE (Center of Documentation, Research and Experimentations on accidental water pollutions, France), on a specific clean-up device that simulates typical operations of cleaning under pressure. The main objective is to develop green formulations for cleaning oil polluted surfaces through a rigorous methodology based on technical and environmental criteria.