bluuebunny/crossref_metadata_2025_split huggingface dataset:
Initial Results from an Acoustic Logging-While-Drilling Tool
Authors: Minear John W. , Heysse Dale R. , Boonen Paul M. 
Published: December 2007

Abstract
This paper presents the initial results from field tests of an acoustic logging-while-drilling tool. Over 60,000 ft of well have been logged with 6.75-in.- and 8-in.-diameter versions of the tool. Various types of formations were encountered with compressional slowness values ranging from 55 µsec/ft to 170 µsec/ft. The tool is configured as a borehole-compensated device; transmitters are located on opposite sides of an array of four receivers. An ultrasonic standoff transducer provides a tool-to-borehole wall distance measurement for data quality evaluation and processing.
Slowness values are computed downhole using real-time waveform processing. Full-waveform data are stored for retrieval and re-processing at the surface. Interactive processing software allows an engineer to reprocess log intervals of poorer log quality and improve the slowness log computed downhole. Downhole-processed and post-drilling-processed slowness logs are compared, and generally show close agreement. These logs also agree well with wireline slowness logs.
Rugose boreholes and attenuating formations can reduce waveform quality. A new rapid-fire technique acquires multiple estimates of slowness as the drillstring rotates through only a fraction of a revolution, and improves slowness quality in rugose boreholes.
Shear-wave energy is clearly apparent in most waveform data. Waveforms can be processed to yield both shear and compressional slowness values. These can then be used to estimate porosity, compute elastic moduli of the rock (for example, Poisson’s ratio, Young’s modulus, bulk compressibility, and shear modulus), and to compute synthetic seismograms for correlation with seismic profiles. Some of these applications of compressional and shear slowness data are discussed with examples.
Transient Analysis To Locate and Characterize Plugs in Gas Wells
Authors: Hasan A.R. , Kouba G.E. , Wang X. 
Published: December 2007

Abstract
We propose to use pressure transient analysis to indicate the location of a flow restriction in a gas well and to characterize such a blockage. We have developed a transient simulator for a gas well with a single partial blockage at any location in the flowline. The early-time wellhead pressure drop is influenced by the volume reduction due to the plug and its location while the late-time steady flow wellhead pressure drops give an indication of the severity of the plug. Thus, the early-time and late pressure response data can be used for blockage detection.
Our study found that the thickness, the length, the location, and the roughness of the plug strongly influence the wellhead pressure response. Of these factors, the extent of reduction in channel diameter (due to plug thickness) has the most effect. In addition, we found that the flow rate at which the test is run has a pronounced effect on both early and late time wellhead pressure transients. We also noted the influence of reservoir pressure on gas density and velocity, which in turn, have some effect on the wellbore storage and the frictional pressure drop. Our study showed that wellbore deviation did not have any appreciable effect on wellhead pressure drop. Geothermal gradient was also observed to have negligible effect on wellhead response. In addition, we found that for most scenarios, the transient pressure response characteristics for off-shore production are similar to those for on-shore wells. Thus, the analysis presented in this report is suitable for off-shore wells as well.

Introduction
Problem Statement. Unwanted flow restrictions are often a fact of life in the oil field. Potential causes for the development of these restrictions are numerous. Fluid properties, coupled with unfavorable pressure and temperature conditions, may lead to formation and deposition of wax, hydrate, asphaltene and scales on the pipe wall. Pipeline configurations could also lead to deposition of sand, buildup of liquid, or formation of vapor lock. Mechanical causes of flow restrictions include stuck spheres or pigs. Other possibilities include pipeline deformation from thermal stresses or mechanical damage.
Once a blockage has occurred, the cause of the restriction is not always easily discernable. Delays in taking appropriate remedial action can cost lost production and could also lead to the development of hazardous situations. Administering the wrong remedial action to remove the plug can be very costly and may even make matters worse.
Often, the type of blockage can be determined if the plug location is known. For instance, a pipe may collapse at a road crossing, or the temperature and pressure conditions in the line may be conducive for different solids deposition over separate but well defined regions. Knowing the blockage location could provide the additional information needed to determine the type of blockage with sufficient confidence to begin remedial action.
P. 653
The Auger Platform: Debottlenecking and Expansion Of Fluid Handling Facilities
Authors: Judd T. R. , Wallace C. B. 
Published: December 2007

Abstract
AUGER, Shell's first Tension Leg Platform (TLP), was installed in 1994 in 2860 feet of water in the Gulf of Mexico. The platform was designed to process 40 MBPD of oil, 100 MMSCFD of gas, and 25 MBPD of water. For most of its operation, the surface fluid handling facilities have proven to be the primary constraint limiting increased production.
Through innovative debottlenecking and expansion of the surface facilities, Auger production rates have recently increased to more than 72 MBOPD and 150 MMSCFD of gas. Further plans are underway to ultimately increase the total platform capacity to 100–140 MBOPD and 300–400 MMSCFD.
This paper will present the original platform design, describe the constraints on the facilities due to higher than anticipated well flow rates and surface temperatures, and discuss the steps taken to reduce the constraints and resolve most problems. These problems include. (1) poor gas/liquid separation efficiency in high pressure separators, (2) excessive natural gas liquid (NGL) condensation in the gas export pipeline, (3) gas dehydration system limitation due to high rates and surface temperatures and (4) other facilities engineering related problems.
Laboratory Investigation of Damage From Guar Gum Base Gels
Authors: Kolb A.K. 
Published: December 2007

Abstract
The damage effect of a guar gum water-based fracturing fluid has been investigated on sandstone and limestone formations furnished by Cleveland Quarries Co. of Ohio. The permeability and porosity of each core was measured before treatment using a high precision micro-permeameter and a high-precision permeameter.
Each core was first saturated with 2% NaCl solution flooded with nitrogen gas and its permeability and porosity were recorded as K and phi, respectively. All samples were then treated with the base-fluid (distilled water) followed by a similar measurement of their permeabilities and porosities. The same cores were once again treated with a guar gum based porosities. The same cores were once again treated with a guar gum based solution ranging in concentration from 20 lbs/1,000 gal to 40 lbs/1,000 gal and their respective permeabilities and porosities were also computed after the treatment. Similar tests were run on the cores by adding 2% CaCl4 and 10% NaCl respectively on the different concentrations of guar. The results revealed that in all cases the core have been damaged and that the magnitude of the damage is not always proportional to the concentration of the guar gum; and in most cases the addition of 2% CaCl2 to the gelling agent solution gave better results than the addition of 10% NaCl. It can also be concluded that the treated guar gum will be more recommended for fracturing limestone formations, while its damage effect for sandstone formations is comparatively high.

Introduction
The use of chemicals as gelling agents in hydraulic fracturing stimulations include both natural and synthetic products. These products fall into the class of high molecular-weight polymers. Synthetic chemicals used in gelling water are very costly and have a tendency to gel more rapidly and produce the same apparent viscosity at less concentration than the natural produce the same apparent viscosity at less concentration than the natural products such as guar gum. products such as guar gum.
Problems Encountered In Drilling and Completing Deep Wells
Authors: Eaton Ben A. 
Published: December 2007

Abstract
Problems encountered in drilling and completing wells to 15,000' and below are reviewed in this paper. Statistical trends in deep well drilling indicate that increasing numbers of such wells will be drilled each year. Problems associated with this activity are similar to those of past shallow drilling. However, these problems are more severe and much more expensive than those in the past.
The role of a drilling coordinator, with regard to the development of sound, workable drilling plans, is discussed. A method of well planning is presented that, if used, will reduce the frequency of expensive problems in deep drilling.
Many of the recurring problems involved in deep drilling are discussed, as are some of the more recent engineering solutions to these problems. This discussion centers not only on the drilling problems, but on some of the completion problems, but on some of the completion problems as well. One such problem involves problems as well. One such problem involves the attempted completion of wells drilled below depths where commercial production is extremely unlikely to be found. A means of avoiding this problem is also discussed.
It is concluded that a great majority of such drilling and completion problems could be eliminated in most cases by better planning, and better trained on-site rig planning, and better trained on-site rig supervisors carrying out the previously agreed upon well plans.

Introduction
Statistical trends in the drilling of oil and gas wells in the United States indicate that the number of deep wells is increasing and that the yearly average depth of these wells is increasing. There are two primary reasons for these trends. The first reason is the fact that there are fewer good shallow prospects to be drilled, and secondly, a real energy crisis is fast approaching in the United States. To avoid this energy crisis problem, operators are spending vast quantities of monies to drill what we will call "deep wells".
For the purpose of this paper, a "deep well" is defined as a well drilled below 15,000' for the purpose of exploring for and producing of oil and/or gas. The first such well was drilled in 1939, but the real increase in this activity started in the 1950's. The statistical trends for the yearly average well depth and number of wells drilled to at least 15,000' are shown in Figure 1.
Developing Block 2 Angola: A Multi-Dimensional Approach to Managing Development Risk
Authors: Morris Ronald L. , Romero Rocky R. 
Published: December 2007

Abstract
This case study focuses on a $380 million project involving the development of eight new offshore fields in Block 2 Angola, which became a success story despite facing major obstacles during early phases of the project. This study highlights how a multi-dimensional approach to managing risk and uncertainty, coupled with excellent cooperation with Partners and government, can lead to an economic success.
With the interruption of the Angolan peace process in 1992, Block 2 became directly affected during the construction phase of the project. For a two year period and until the signing of the Lusaka Peace Accords in 1994, which reestablished a cease-fire in Angola, mitigation of risk and uncertainty became the primary driver in completing this project. As a minority shareholder in Block 2, Texaco - Angola (Texaco Panama Inc. - Angola) as Operator needed to gain consensus among all its Partners and government for a revised development plan, taking into account some very divergent views of the risks facing the partnership. Ensuring the security of personnel, continuity of income, and maintaining sound project economics were required to gain the consensus needed to move ahead. A complete re-design of the development concept ensued while in the construction phase. The result was that this project was completed some 3 years later with acceptable economics.
Unconventional and innovative design, financial hedging and project management solutions will be highlighted to illustrate how this was accomplished.
Dehydration of Crude Using Electrostatic Treaters: Development of Design and Operating Guidelines
Authors: Khatib Z. I. 
Published: December 2007

Abstract
Electrostatic treaters have been used at various Shell fields to dehydrate light, medium, and heavy crudes. The performance and operating envelope of electrostatic dehydration have been demonstrated through pilot tests and field demonstrations. Oil throughputs of 200-300 BOPD/ft2 of grid area for light crudes (30-35° API gravity) and 10-20 BOPD/ft2 for heavy crudes (11-14° API gravity) were shown to be adequate for producing pipeline-quality crude. Implementation of these design rates could lead to tangible capital savings in reduced size and dead weight (important to tension leg platforms) as well as in reduced operating costs.
Well Control Incidents are CRINE and Safety Opportunities
Authors: Hamilton T 
Published: December 2007

Abstract
The United Kingdom Health and Safety Executive (The HSE) engages in scientific activity mainly to develop its understanding of the hazards, to assist in the formation of standards needed for regulation and to enable it to challenge and form independent judgements on industrial activity that may be unsafe. One focus of attention over several years has been oil and natural gas well control. In 1992 The HSE Offshore Safety Division (OSD) embarked on a well control incident assessment programme using a new computer simulation tool and data on specific oil based mud incidents supplied by Operators. This phase of a larger ongoing programme set out to prove and exploit the new tool and insights into kick fluid mechanics produced from earlier research projects to achieve safer well control.
OSD’s programme is focused on the kick control phase in well control incidents where the risk of escalation is highest. After proving that the simulation tool could model actual field experience accurately in selected incidents the programme was extended to show a wider range of incidents could be modelled. The way is now open to sharing experience by sharing technical details of events, actions and behaviour of fluids in wells during incidents. Sharing experience more widely is a practical and effective way of improving awareness and safety performance. In addition it should bring cost saving in a similar way to that heralded by the Cost Reduction in the New Era (CRINE) programme. Step changes in safety and cost reduction performance require similar changes in culture to secure success.
The paper reports the results of collaboration with industry between 1992 and 1995. It describes experience in modelling from field data, incident evaluation and developing communication tools and then looks forward and describes the aims and objectives of current work in the main programme.
Risk Assessment of Hydrocarbon Releases during Workover and Wireline Operations on Completed Wells on Offshore Platforms
Authors: Edmondson J. N. , Hide D. K. 
Published: December 2007

Abstract
Safety Regulations in the UK require operators to demonstrate that the risks to workers from well operations on offshore platforms have been reduced to the lowest level that is reasonably practical. Each offshore platform in the UK has a safety case which includes a quantified risk assessment of well operation hazards with the potential to cause a major accident.
Assessment of the safety cases by the UK Health and Safety Executive (HSE) showed that few operators have specifically analysed risks resulting from well workover or wireline operations, regarding such risks as subsumed within general blowout risks. Where workover/wirelining have been considered separately, the risk estimates have been determined from average worldwide historical hydrocarbon release frequencies and not by analysis of particular operations being carried out on a specific platform. The prevalent conclusion from such risk analyses is that the contribution of workover/wireline risks to the total platform risk levels is very small. In order to evaluate whether such a conclusion is necessarily valid in all cases, HSE undertook a study to establish a method for estimating workover/wirelining risks for a number of different types of platform.
This paper describes the method used by HSE to assess the risk of hydrocarbon releases during workover and wireline operations. The workscope was restricted to completed wells on offshore platforms. The method is based on a detailed analysis of all the different potential failure modes associated with the various well intervention operations carried out on these platforms. The failure mode analysis results are then used to estimate the significance of these risks relative to risks from other activities on these platforms and to assess where the use of average historical release frequencies could be justified and where additional analyses are necessary. The study also provides a mechanism for identifying those workover/wirelining operations which are predicted to give rise to the highest risks and for which risk control measures should be reviewed very closely.
Application of Non-Conventional Wells to Infill
Authors: Mochizuki Satoshi 
Published: December 2007

Abstract
The objective of this study is to find the effectiveness of non-conventional wells as infills under miscible gas and WAG (water-gas alternating injection) floods. Ten types of non-conventional wells are investigated and the results show that the performance of non-conventional wells strongly depends on types of wells, flood size, operational conditions, drive mechanism and reservoir characterization. Therefore, these factors must be carefully considered in optimizing the selection of wells and operating scenarios
Structural dynamic monitoring on Vega platform: an example of Industry and University collaboration
Authors: Musso A. , Spadaccini O. , Vignoli A. 
Published: December 2007

Abstract
Dynamic study of Vega platform has been carried out to estimate the significant uncertainties connected with mathematical modelling and evaluate their influence on the predicted structural response. The comparison between the design hypotheses and the structural response has been performed using the informations collected by existing monitoring system of the platform. The modal analysis, computed for a range of the significant parameters, has shown the correlation between damage states and changes in the dynamic characteristic of the jacket, which are fundamental elements to evaluate the structural response of the platform after a enviromental event. The possibility to associate the variations of dynamic response, collected by appropriate program of continuous or periodic monitoring, to the fatigue life of the welded joints and to structural collapses can be of great help to the ordinary techniques of inspection. This possibility, besides, can allow an appreciable reduction of the expensive conventional underwater inspections, without interferring in the normal operativity of the platform.
Multiple Frac-Pack Stimulations of Deviated, High-Permeability Water-Source Wells
Authors: Finley D. B. , Chong K. K. , van Domelen M. L. , Kaweeyanun P. 
Published: December 2007

Abstract
This paper presents a case history of technology applied to perform multiple ffac-pack treatments in three deviated water- source wells in Central Thailand. Each of the three wells had been sidetracked from its original completion because of previous production problems. The multiple target zones in these wells were soft, high-permeability, unconsolidated sandstones that lacked barriers for fracture containment. Given these conditions, ffac-pack completions were designed and implemented. Frac- pack treatments are small hydraulic fractures designed for relatively short fracture lengths and high conductivity. The ffac-pack treatments, which minimize the effects of near-wellbore damage, are generally followed by the placement of a conventional gravel- pack to ensure that sand production does not occur. This type of completion technology, relatively new to the Asia-Pacific region, should be considered in areas where conventional sandstone acidizing and gravel-packing operations have yielded unsatisfactory results.
Technology and operational considerations for this type of completion scheme were as follows: possibility of multiple hydraulic fractures resulting from long perforated intervals in the deviated wellboresapplication of sand slugs to reduce/eliminate excessive near-wellbore friction pressureson-site minifrac analyses performed immediately before each frac-pack to optimize the main treatment designplacement of sand plugs for zonal isolation in lieu of mechanical, drillable bridge plugs to reduce rig time while the treatments were performed
This paper presents the technology applied to address each of the previous considerations and water production results to date for each of the three wells.
Reservoir Simulation Modeling of Natuna Gas Field for Reservoir Evaluation and Development Planning
Authors: Fenter D. J. , Hadiatno D. 
Published: December 2007

Abstract
In the development planning studies of the Natuna gas project, a three-dimensional, two-phase reservoir simulation model of the Natuna gas field was used for evaluation of the gas reservoir and as a planning tool. A detailed sequence stratigraphic study of the gas field that incorporated seismic, well log and core data provided the basis for the geological model used in the reservoir simulation model. The objective of the development planning studies was to determine production well locations, production well drilling schedules, the total number of wells required, the timing for the installation of wellhead compression equipment and the gas production profile for the field as a function of time. The reservoir is estimated to be able to sustain a 2,400 million standard cubic feet per day (Mscf/d) methane production rate for 30 years or more.