bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cement Slurry Performance and Set Cement Properties vs. Microsilica Densification
Authors: Daou Fatma , Piot Bernard 
Published: March 2008

AbstractMicrosilica is the extremely fine noncrystalline silica obtained in electric furnaces as a byproduct in the manufacture of elemental silicon and ferrosilicon alloys. This waste material, also improperly called silica fume, is available in different grades of various handling characteristics. It has been used for years as cement admixture both in the oil field and in construction and civil engineering industries. Because of its extremely fine nature and high reactivity as a pozzolanic material, microsilica has been used to improve slurry stability and the mechanical properties of the hardened material.This paper reviews typical uses of microsilica in oilfield cements. Particular attention is given to the influence of material grade, in terms of degree of densification, on slurry behavior and set cement properties. The physical properties of microsilica tested include specific gravity, loose and compacted bulk densities, and particle size distribution before and after being submitted to an ultrasonic treatment. Slurry behavior is evaluated in terms of rheology and stability.The observation of set microsilica cement microstructure with a scanning electron microscope coupled with an energy dispersive spectrometer clarifies the question concerning the dispersability of densified microsilica in cement slurry. An unambiguous correlation between physical properties of microsilica, slurry performance, and set cement morphology is then established, leading the way to correctly specifying the quality of microsilica to be used in oilfield applications.This work demonstrates that, contrary to common belief, not all grades of microsilica are equal, and that densified microsilica does not redisperse into small particles when mixed in a cement slurry. Therefore, densified grades, which are popular for their ease of handling, do not provide the performance required for adequate zonal isolation as is normally expected from microsilica slurry. In particular, densified material improves neither the slurry stability nor the set cement permeability and mechanical properties.
Zonal Isolation in Reservoir Containing CO2 and H2S
Authors: Moroni N. , Repetto C. , Ravi K. 
Published: March 2008

Abstract
Carbonate reservoirs are often characterized by high pressure and high content of H2S and CO2. For these reasons, drilling the reservoir is the most challenging activity of such fields and long-term zonal isolation across the reservoir section is one of the primary requirements.
In the example well considered for this study, the production liner is set at a depth of approximately 4,500 meters and the mud density is 16.2 lb/gal (1.95 g/cc). After a production liner is cemented, the well undergoes several operations such as fluid displacement, casing/liner pressure tests, stimulations, production, and injection; these operations create load on the cement sheath.
Carbonation of neat Portland cement systems in CO2 environments is well known in the industry. The carbonation is of significant concern if the CO2 can enter the cemented annulus. The surface area of the cement sheath that contacts CO2 should be minimized to help prevent carbonation. This can be achieved by reducing the permeability, preventing the formation of cracks and micro-annulus, and reducing the components in the cement sheath prone to attack from CO2.
To assure long-term sealing properties of the cement sheath during the life of the well, a cement formulation has been developed to be mechanically durable and chemically resistant to aggressive environments. The cement system discussed in this paper was designed to withstand the stresses imposed by changes of pressure regime during the well life by improving elasticity and thus helping prevent damage to the cement sheath. In addition, the potential for carbonation was limited by reducing the components in the slurry formulation that could react with CO2. Mechanical properties and resistance to CO2 environments of the cement system were tested in the laboratory.
The cement system was successfully evaluated in the yard test. Cement sheath analysis, slurry design and testing are discussed. The results presented in this work should help in the design and implementation of solutions to contain reservoir fluid and injected fluids, including in the presence of H2S and CO2.
Evaluating the True Cost of Losing a Bottomhole Assembly
Authors: Tollefsen E. , Weber A. , Crowell D. , Nagy Z. 
Published: March 2008

Abstract
Losing a bottom hole assembly (BHA) is one of the most costly unplanned drilling events that can occur for an operator. Time spent fishing for the lost assembly, the rig time wasted waiting on the mobilization of equipment and people, as well as the additional costs of whipstocks, cement, and directional tools significantly increase the cost of a well and often results in exceeding the approval for expenditure (AFE). The new well plan may also lead to any number of problems with tortuosity and torque-and-drag farther down the wellbore. Typically, these expenses are invoiced individually, obscuring the cumulative cost to reach the same true vertical depth (TVD) as the stuck assembly.
Often, one of the largest invoices the operator receives during a stuck BHA event is the replacement cost of the logging while drilling (LWD) technology. This large expense does much to disguise the other costs of sidetracking, leading many operators to consider the risk of losing a high technology LWD tool far greater than the benefits of running it in the hole.
As well difficulty increases and the risk of a stuck pipe event grows, operators become hesitant to run larger LWD tool strings in the hole. Unfortunately, this mentality creates a paradox. Many of the new LWD technologies including annular pressure while drilling, formation pressure while drilling, sonic while drilling and seismic while drilling are capable of significantly reducing the risk of a lost-in-hole (LIH) event. In the event this technology is LIH, the additional information to analyze and replan the new wellbore can prove to be invaluable.
This paper will analyze data and case studies in the Gulf of Mexico (GOM) to perform a risk analysis that includes the true cost of sidetracking a well, with and without additional LWD technology in the drill string providing key real-time measurements.
Requirements for a Full Drill through Subsea Wellhead and Tree System
Authors: Lewis Sterling , Suter Jay 
Published: March 2008

Abstract
This paper describes the requirements realized in the development of a full drill through subsea wellhead and tree specification. Drill through wellhead and tree systems provide an opportunity for capital and operating expense savings. Given a target development, definition of requirements determines potential savings, performance, and necessary contingencies.
Current industry practice considers both slim bore and drill through wellheads and trees. However, operational interfaces may not be fully apparent. The case considered is an 18¾-in. wellhead with a 13⅝-in. nominal hanger bore. The system interfaces a standard 21-in. outside diameter riser and an 18¾-in. horizontal subsea tree. The full drill through system is capable of drilling out and running a 10¾-in. casing and installation of the lower and upper completion with the subsea tree installed.
Primary design considerations include the casing program, sequence of operations, protection of seal bores, and primary and contingency operations. Seal surface protection is important for the reduced wellhead bore design. The reduced bore increases the exposure of casing hanger and running tool seal areas. Normally, primary operations take place through the tree; however, contingencies must consider operations without the tree installed. Thorough understanding of the requirements achieves an optimized drill through system.
Are Casing Centralization Calculations Really Conservative?
Authors: Guillot D. J. , Froelich B. , Caceres E. , Verbakel R. 
Published: March 2008

Abstract
Since the early 1940s casing centralization has been identified as being key to efficient mud removal and therefore to successful primary cementing. Prior to a job it is common for field engineers to spend time optimizing casing centralization using commercially available or proprietary software, in particular for highly deviated wells. However predicted casing centralizations suffer several limitations due a number of possible assumptions. For example, the mechanical response of centralizers is usually characterized in a single hole size, and different rules are used to extrapolate their behavior in different hole sizes. Needless to say, there are not too many holes that are perfectly in gauge and therefore centralization calculations in out-of-gauge sections can be questioned.
With the recent introduction of a new generation of cement evaluation tools making use of flexural waves propagating vertically along casing and radiating into the annular space, it may be possible to measure the time of arrival of the cement/formation interface echo and therefore to measure casing eccentering. Therefore, one can now compare the calculated casing centralization to the one measured downhole.
The objective of this paper is to review some of the current limitations of casing centralizer calculations as they are being performed in the field on a day to day basis. The analysis is supported by a comparison between measured and predicted casing centralizations on a number of field cases. Examples showing the effects of the observed discrepancies on cement placement using a displacement simulator are discussed. Recommendations to improve centralization predictions are proposed.
Application of Flow-Control Devices for Water Injection in the Erha Field
Authors: Haeberle David C. , Nwankwo Anthony , McDermott Jim R. , Duffy Brian W. , Gosavi Shekhar , Grubert Marcel 
Published: March 2008

Abstract
The Erha field is a deepwater subsea oil development located in OML 133 off the coast of Nigeria. Erha North is a satellite of the Erha Field and is characterized by multiple unconsolidated sand intervals separated by shale sections. Due to the potential for reservoir compaction and early water breakthrough in these multi-layered Erha North reservoirs, high rate water injection is an important element of primary production through pressure support and is considered critical to project economics and reserves capture.
This paper presents a case history of a successful field application of an innovative water injector completion technique addressing the issue of long-term injection conformance. Standalone screens with flow-control devices (i.e., downhole chokes) and openhole packers were utilized on the two most challenging water injectors in the Erha field. The completion objectives were: (a) target multiple intervals to reduce well count and cost, (b) sustain target injection rates and allocations, and (c) install sand control to prevent wellbore fill. Traditional water injector completion techniques, such as frac packs or openhole standalone screens, were judged to be incapable of meeting all the completion objectives. Unfractured completions, such as openhole standalone screens, have been reported to lose injectivity over time due to plugging and require fracturing to sustain injection rates (Sharma 2000). Fracturing may result in poor injection conformance and has the potential for broaching cap shale. Application of stacked completions or intelligent well systems would have added significant cost and complexity.
Detailed completion simulations and fracture modeling were conducted to design the completions to their unique geologic settings. It is expected that this completion technique will maintain the desired injection allocations to the multiple target intervals over the well life in the matrix and fracture injection regimes. Upfront planning, communication, and alignment between reservoir, subsurface, and drilling functions enabled a successful real-time completion design and resulted in an operational success with less than 5% completion non-productive time (NPT). Performance of the injectors is being monitored by downhole pressure and temperature gauges.
Building a Well Control Culture with WellCAP
Authors: Kropla S. M. , Kelly O. A. , Gillis T. , Sonnemann P. , Metcalf J. J. , Santos O. L. A. , Rodrigues R. 
Published: March 2008

Abstract
Heightened levels of industry activity have put an increased focus on all types of training, particularly in the critical area of well control. The development of competent personnel capable of recognizing, avoiding and mitigating well control situations requires industry-developed systems capable of establishing necessary training standards and quality assurance programs that monitor training provider performance, both essential elements for ensuring proper skills development through fit-for-purpose training.
The Well Control Accreditation Program (WellCAP) operated by the International Association of Drilling Contractors (IADC) is designed to provide the drilling industry the building blocks for a comprehensive "well control culture" beginning at the floorhand level and continuing to the most seasoned drilling personnel.
Rig workers are introduced to the basics of well control equipment at the Introductory Level. Simulator exercises provide a higher level of practical knowledge at the Fundamental Level, recommended for Derrickmen, Assistant Drillers and Drillers. More complex simulator exercises and calculations are a component of the Supervisory Level, designed for drillers, toolpushers, superintendents and drilling foremen. WellCAP Plus is the latest addition to IADC's WellCAP system, which introduces a new learning model focus on highly experienced employees.
Since the program was first implemented in 1995, WellCAP's curriculum offerings have evolved steadily to keep abreast of industry needs.
Reducing Equipment Integration Cost and Risk in New Rig Construction
Authors: Reid David , Hoeflich John , Ogg Jeremy 
Published: March 2008

Abstract
By reminiscing about new drilling rig construction for the last 15 years, this paper proposes a change of thinking in reducing both cost and risk through the application of lessons learned. Every individual who has been involved in building rigs carries their own lessons learned forward, and they naturally apply them to their next construction project. Historically, these collective lessons have not been proactively focused for the good of the industry. Therefore, the intent of this paper is to draw upon the concurrent themes of these lessons learned and, in turn, propose industry-wide solutions when dealing with new-rig construction.
The group with the broadest exposure to execution challenges, and the subsequent source of the information within this paper, can be found with the suppliers, installers, and integrators of the equipment and controls on new-build rigs. In our most recent construction cycle, the introduction and application of the most successful past-era behaviors has removed considerable risk from the emerging processes. The emerging processes that have been developed are the product of increases in complexity and the subsequent integration challenge that comes from numerous control systems. However, as it is known, these control systems are expected to work as one harmonious drilling machine, and historically this has not been the case! Impressive early results have shown marked improvements with the implementation of complete standard rig designs. These results have reduced the overall risk, and in some cases, they have shown how the innovative utilization of simulators early in the process to try and face construction woes, prior to the actual construction process, can avoid hitting a bottleneck in the process.
Using the Last Several Years of QHSE Data to Improve the Next Several Years of QHSE Performance
Authors: McClaine Rick , Stough Joe 
Published: March 2008

Abstract
Have you found the Leading Indicators for which continued execution TRULY does result in fewer injuries, less spills, and generally better HSEQ performance? If so, can you prove it? If not, is it something you wish to do?
This paper will dive into the increasingly hot topic of "Leading Indicators" and how combining a large global data set with some fundamental statistical methods can result in both finding those factors which TRULY affect performance outcomes and the mathematical support to prove it.
Barnett Shale Drilling and Geological Complexities—Advanced Technologies Provide the Solution
Authors: Janwadkar Sandeep , Morris Stephen , Thomas Mark , Jackson Garrett , Roberts Geoff , Fortenberry David , Kramer Mark , Dennie Devin 
Published: March 2008

Abstract
The Barnett Shale field of North Texas is the most prolific and fastest growing natural gas field in North America.1 The field has a multi-trillion cubic feet equivalent upside potential, but efficient extraction of natural gas from the Barnett shale poses drilling and geological challenges. Geological complexity of this field requires precise placement and drilling of the well as per the directional well plan.
Some of the major drilling challenges that affected drilling efficiency were downhole drill-string dynamics, high torque and drag, hole pack-offs and loss circulation. Engineers determined that early detection of downhole problems such as high vibrations, poor hole cleaning and high equivalent circulating densities (ECD) were key to improving drilling performance.
To overcome these challenges state-of-the-art advanced technology tools were run to acquire real-time drilling data and images. Real-time drilling data acquired was inclination/azimuth close to the bit, bore/annular pressure and vibration/stickslip. Drilling data gathered in real-time were crucial to detect and eliminate potential drilling problems before they became a problem. Real-time geological data transmitted to surface were formation resistivity and azimuthal gamma ray measurements. High-resolution images were developed from real-time azimuthal gamma ray measurements. These images could be utilized to precisely detect bed boundaries and accurately estimate formation dips.
This strategy has been implemented to drill several wells in the Barnett Shale with excellent results. Advanced technologies have helped in significantly improving drilling performance and in precise placement of the wellbore. Significant reduction in rotating hours has been achieved.
Trapped Annular Pressure Mitigation: A Spacer Fluid That Shrinks: Update
Authors: Bloys B. , Gonzalez M. , Lofton J. , Carpenter R. , Azar S. , Williams D. , McKenzie J. , Capo J. , Hermes R. , Bland R. , Foley R. , Harvey F. , Daniel J. , Billings F. , Robinson I. , Allison M. 
Published: March 2008

Abstract
In deepwater or other sub-sea completed wells, fluids, usually spacers or drilling fluid, are commonly trapped in casing annuli above the top-of-cement and below the wellhead. When these trapped fluids are heated by the passage of warm produced fluids, thermal expansion can create very high pressures (10,000 -12,000 psi or more) and cause the collapse of casing and tubing strings.1,2,4,12,15
Mitigation methods such as vacuum insulated tubing to limit heat transfer,6,7,14 nitrogen-based foam spacers to give highly compressible trapped fluids,8,9,10,11 crushable urethane foam,3 etc. are somewhat successful but are either very expensive, logistically troublesome or have unacceptable failure rates. This paper continues the discussion of a new approach which has created a water-based spacer fluid that will be used just ahead of the cement. The spacer contains perhaps 10-30% of emulsified liquid methyl methacrylate monomer (MMA). Upon polymerization, the MMA phase shrinks by 20%, creating room for the remaining fluid to thermally expand without creating catastrophic pressure. The polymerization is triggered by heat and a chemical initiator. The target temperature can be controlled by choosing an appropriate type and concentration of chemical initiator. Premature polymerization during spacer placement can be prevented by an appropriate type, and amount, of inhibitor. The initial lab work and a mid-scale field trial of this technology were reported in detail in SPE/IADC 104698.1
This paper covers the development and field testing (land) of all the equipment and processes necessary to apply the technology in deep water.
Well Test Analysis in a Lean Gas Condensate Reservoir
Authors: Yatindra Bhushan 
Published: March 2008

Abstract
The Raageshwari Deep Gas Field, situated at the northern end of the Central Basin High within the onshore RJ-ON-90/1 Contract Area, Rajasthan State, India, was discovered in 2003. It is a tight lean gas condensate volcanics reservoir, with excellent gas quality of 80% methane and low CO2 and no H2S content. Since discovery, several appraisal wells have been drilled in the field and tested extensively. The wells have produced gas rates in the range of 2-4 MMscf/d with condensate gas production ratios in the range of 40-50 STB/MMscf. The drawdowns during the production tests have been high, in the range of 3000-4000 psi, indicating the very low permeabilities of the reservoir. This paper describes the tight volcanic reservoir, the reservoir fluid present in it and the well test analysis results from several wells drilled in the field. The reservoir being very tight, the well tests have been carried out for long time periods, extending beyond a month, to enable deriving of meaningful information. As during testing the pressure drops below the dew point in areas around the wellbore, condensate dropout is expected to occur, influencing the relative permeabilities for gas and condensate flow. Radial composite models have been found to allow reasonable matching of observed test behaviour.
Several hydrofracturing jobs have been carried out in these wells. Well tests carried out after completion of hydro-frac jobs have also been analysed and presented.
Waterflooding Viscous Oil Reservoirs
Authors: Beliveau Dennis 
Published: March 2008

Abstract
In 2004, the large Mangala, Aishwariya, and Bhagyam oilfields were discovered in the remote Barmer Basin of Rajasthan, India. These fields contain light, paraffinic crude oils with a wax appearance temperature approximately 5°C less than reservoir temperature, and in situ viscosities that range from ~8cp to ~250cp. Development plans for these fields are based on hot waterflooding to prevent problems with in situ wax deposition.
This paper discusses a few issues associated with waterflooding viscous oils, presents some viscous oil waterflood results from around the world, and benchmarks the expected performance of the Rajasthan fields to this database. Given that the Rajasthan oils have some properties that may be considered "unusual" and potentially troublesome for waterflooding, and that there is no long-term production data or a history-match of waterflood performance in hand, these benchmarks were considered very important reality checks. In actual fact, fields with similar or much higher viscosities are routinely waterflooded with excellent recoveries in Canada, the USA and elsewhere.