bluuebunny/crossref_metadata_2025 huggingface dataset:
Are Casing Centralization Calculations Really Conservative?
Authors: Guillot D. J. , Froelich B. , Caceres E. , Verbakel R.
Published: March 2008

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

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

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

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

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

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

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

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

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.
Designing a Core Analysis Programme for the Mangala, Bhagyam and Aishwariya Fields—Ensuring Value for Money
Authors: O'Sullivan T. , Beliveau D. , Kumar H.
Published: March 2008

The Mangala, Bhagyam and Aishwariya fields are located in Rajasthan and collectively contain approximately 2 billion barrels of STOIIP. During the appraisal of these fields, more than 1.7 kilometers of core was collected from the principal reservoir, the Fatehgarh Group Formation.

This paper illustrates the methodology used to highgrade the geological units and pick specific points for special core analyses so that maximum technical information was gained for minimum cost. The criteria considered for highgrading the points were a combination of STOIIP content, facies type and porosity-permeability variation.

Sensitivities were also run on the parameters that are input to the STOIIP calculation and recovery estimates to ensure that adequate analyses had been conducted on the key parameters. The approach as defined in this paper enabled a significant increase in STOIIP for these fields that could be clearly demonstrated and supported by the core analysis data.
Mangala Field Permeability Measurements: Comparison of Core, Wireline and Well Test Data
Authors: O'Sullivan T. , Beliveau D. , Praveer K. , Tandon R.
Published: March 2008

Permeability is a measure of the ability of a reservoir rock to transmit fluids, and is arguably the most important parameter within a simulation model. For the Mangala field, permeability has been measured extensively from core analyses, wireline logging and well test analyses. Implicit in each of these measurement techniques is a specific scale and measurement direction. It is thus not surprising that differences still remain even after correcting the measured permeabilities from various sources to an absolute permeability.

This paper presents the detailed methodology that was used for the calculation of permeability from the various sources and discusses possible explanations for the differences in the numbers.

In some of the lower reservoir units, Mangala core permeabilities are significantly higher than the permeabilities measured from well tests, and it is proposed that permeability "baffles" on a multi-meter scale may be causing this decrease in well test permeabilities. These "baffles" are related to depositional features (e.g. current bedding and channel pinch-outs) and are likely to be strongly directional, leading to a horizontal permeability anisotropy which has important implications for reservoir development.
Underwater Laser Drilling: Drilling Underwater Granite by CO2 Laser
Authors: Kobayashi Toshio , Nakamura Masahiro , Okatsu Komei , Ohtani Kiyonobu , Takayama Kazuyoshi
Published: March 2008

The purpose of this research is to develop Underwater Laser Drilling Technology in drilling and completing oil and natural gas wells. Recent challenges in oil fields are caused by: the geometry of oil or gas wells is becoming more complicated in profile; drilling in hard formations like granite requires more tripping times for changing rotary bits made of steel; as the water depth at which floater rigs can operate increases, tripping has to take longer than ever. Underwater Laser Drilling is a key to solution of these challenges since the laser may allow for non-contact / non-rotating drilling method. Granite is one of the most difficult rocks to be drilled by lasers. Consequently, no successful report has been found on underwater granites drilled by lasers. This paper describes experimental tests of irradiating carbon dioxide (CO2) laser to granite submerged in water/bentonite solutions. Sample granite was submerged at 50mm from the water-surface and then a CO2 laser with a wavelength of 10.6μm which has a high absorption coefficient in water was intermittently irradiated into the 4wt% bentonite solutions. A laser induced underwater shock waves, cavitation bubble formations, and micro-water jet formations upon bubble collapse. The high power laser beam locally melted the granite into molten glass, which successively turned to a molten glass bead. The generated glass beads were small enough to be removed out of the created hole. A high-speed video camera was employed to record the laser beam in the water. We observed the generation of initial cone shaped water bubbles through which the laser beams reached bottom rock surface with a minimum absorption energy loss. The laser beam indeed drilled the granite specimen submerged in the solution. The research will continue to collect data for designing a prototype.
Upgridding 3-D Geologic Models in a Channel-type Environment
Authors: Talbert Matthew , Ma Xianlin , Datta-Gupta Akhil
Published: March 2008

The development of coarsened reservoir simulation models from high resolution geologic models is a critical step in a simulation study. The ‘optimal' coarsening becomes particularly challenging in a fluvial channel environment where the channel sinuosity and orientation can result in pay/non-pay juxtaposition in many regions of the geologic model. Under such conditions, a uniform coarsening will result in mixing of pay and non-pay and will most likely result in geologically unrealistic simulation models and erroneous performance predictions. In particular, the upgridding algorithm must keep pay and non-pay distinct through a nonuniform coarsening of the geologic models. In this paper we present a coarsening algorithm to determine an ‘optimal’ reservoir simulation grid by grouping fine scale geologic model cells into effective simulation cells. Our algorithm groups the layers in such a way that the heterogeneity measure of an appropriately defined ‘static’ property is minimized within the layers and maximized between the layers. The optimal number of layers is then selected based on an analysis resulting in the minimum loss of heterogeneity because of upgridding. We demonstrate the application of the optimal gridding by history matching waterflooding in a structurally complex and faulted offshore turbiditic oil reservoir. The field is located in a prolific hydrocarbon basin offshore South America. Permeability and fault transmissibility are the main uncertainties. More than 10 years of production data from up to 8 producing wells are available for history matching. We demonstrate that any coarsening beyond the degree indicated by our analysis overly homogenizes the properties on the simulation grid and alters the reservoir response.
Pipeline Maintenance and Management in Inter-tidal Region - A Case Study
Authors: Pant Himanshu , Kumar Ujjwal
Published: March 2008

The pipeline system is regarded as the safest and the most economical system for transportation of hydrocarbons across the country. Pipelines of various sizes and lengths crisscross the continents supplying both processed as well as unprocessed crude oil and gas from the producing region to the consumer.

Though the advent of pipeline and its development occurred concurrently with the development of the hydrocarbon industry, but like the oil industry, the pipelines also keep on throwing new challenges requiring human ingenuity.

The present paper presents the approach taken by the National Oil Company of India in maintaining and operating a 36" pipeline transporting unprocessed sour gas (150-160 ppm of H2S and nearly 7% CO2) from offshore field to the onshore gas processing plant.

The paper explores the various options evaluated to maintain the health of the pipeline which travels through various profiles with special attention to the landfall point, where the pipeline faces alternating exposure of a dynamic meandering river which has changed its course many a times resulting in generation of free spans.
Techniques in Marginal and Mature Fields in the Pannonian Basin, Hungary: Case Study
Authors: Holoda A. , Palásthy Gy.
Published: March 2008

In Hungary the oil production started in the middle of 30's in the last century. Intensive exploration activity in the region had resulted sustainable increase in the recoverable oil and gas reserves. In the early 80's, however, this tendency stopped, the size of new discoveries have been continuously decreasing consequently a declining phase in the production pointed out the importance of rejuvenation of the existing mature and marginal fields. Production operation of the large fields required more attention and finding all the stranded barrels of HC became a strategically important company task including but not limited to research and introduction of new EOR/IOR technologies.

MOL, as one of the largest operators in the region has introduced and successfully implemented wide spectrum of enhanced and improved techniques in the maturing oil fields. Application of horizontal wells, infill drilling, 3D seismic programs, state of the art geological modelling, methane and CO2 injection, improved water flooding will be presented highlighting the added values of different solutions in these projects. Currently MOL operates more than 100 fields in the Pannonian basin. Recovery factor of these fields exceeds 35-40% for oil and 60-75% for gas. How to progress: cost effective solutions or more expensive new technologies are the better approach? This paper will deliver some exciting examples for both situations.
Microbial Enhanced Oil Recovery (MEOR) with Special Emphasis to the "Uneconomical Reserves"
Authors: Rafique Maqsood Ahmad , Ali Usman
Published: March 2008

While demand for petroleum products continuous to rise, petroleum production worldwide is in a steady decline. However, new developments in technology and the rise in world oil prices give promise that substantial portions of otherwise neglected oil can be recovered. So in the continues race of exploring petroleum, recovery of known reserves must be improved if the goal of avoiding shortages is to be met.

One of the promising recovery methods is the microbiological enhanced oil recovery (MEOR). MEOR technology has the potential to be one of the reliable technologies that suits best the economic constraints of the current oil markets. The technology is a potential alternative to other EOR/ IOR methods, as it is being implementing in most parts of the world with satisfactory results not only from economics point of view but also from having lesser environmental impact.

The paper provides a review on MEOR technology and discusses it with special emphasis to marginal and/or uneconomical reserves. The goal of cost reduction, which is a major objective in any recovery methods, can be met by using MEOR technology which involves injecting a small amount of a solution containing microorganisms to spread through the reservoir and consequently produce desirable chemicals and gases that will enhance oil recovery and therefore profit. The paper also outlines the strategies to identify and meet the challenge of recovering large proportions of oil using MEOR techniques which could be very helpful in closing the energy gap by draining large proportions of oil which is left behind and minimizing the supply and demand difference in today's "energy hungry world".
Novel Liner System Improves Coring Performance, Rig Safety, and Wellsite Core Processing
Authors: Hall Larry M. , Wilson Bob T. , Norrie Alan G.
Published: March 2008

A one-piece aluminum inner barrel liner system has been employed to protect and containerize core material during coring operations with conventional and wireline core barrels. The system offered enhanced safety features and improved core handling on the rig floor. The integral one-piece liners securely containerized the core during acquisition. Vent holes allowed expelled gas to escape during recovery to the surface, improving safety during core retrieval and handling. The companion Non-Rotating Inner Tube Stabilizer system will ease separation of the 30-foot liner joints, thus improving wellsite handling procedures and safety during extended core runs. The design allowed the liners to be opened quickly and easily at the surface for rapid examination and sub-sampling of the core material.
Lessons Learnt from over 20 Years of 4-D Deployment
Authors: Foster Dave G.
Published: March 2008

This paper reflects back on the major trends, successes and lessons learnt of BP's 4-D deployment over the last 20 years, and offers insights into the main considerations for developing 4-D strategy in emerging areas.

Since the early 1990's, BP has been developing and deploying 4-D technologies across a range of different environments and reservoir situations. Up to the end of 2007, over 115 surveys have been acquired*, about 85 operated and 30 non-operated. This experience base represents a significant proportion of industry 4-D history, and when analysed, can offer valuable insights into developing future 4-D strategy and tactics for new fields and basins. 4-D has most commonly been used in oilfields under water-flood due to the ease of monitoring large saturation and pressure changes and the increased complexity of reservoir management, which gives the opportunity for large commercial impact. Monitoring of gas field depletion has added clear value in appropriate situations, but is much less common due to the generally simpler reservoir management issues and smaller infill programs. The dominant acquisition technology deployed has been towed streamer surveys every 25 years, but BP has now also installed the world's first three permanent ocean bottom cable (OBC) monitoring systems to deliver high-quality and frequent 3-D and 4-D data.

4-D application is continuing to expand globally, and BP itself is currently expanding 4-D application from the historical core areas of the North Sea and Gulf-of-Mexico into regions of new and existing production, such as deepwater Angola, and Alaska respectively. Development of 4-D strategies for new areas and basins requires an assessment of both technical and commercial applicability.
Monitoring of Polymer flood project at Sanand field of India
Authors: Dass Chanchal , Jain Manisha Ajay , Dhawan Ashwani Kumar , Misra Tilak Ram
Published: March 2008

Sanand is the only oil field in India where field-scale polymer flooding is going on for the last twelve years. The field was discovered in 1962 and commercial production commenced from 1969. In view of high mobility contrast and predicted poor recovery of around 15% of OIIP under depletion drive, polymer flooding was adopted as an IOR process for improving oil recovery from this field. An inverted five spot polymer pilot project was started in 1985. Based on the encouraging result of the pilot, the polymer injection project was expanded to a larger area in 1993 and field-scale implementation has commenced from 1995. As on July 2007, the recovery from the field is around 24% with 68% water cut. Envisaged recovery from the field is around 36% with 77% water cut by 2020 with continuance of polymer injection up to 2013 followed by chase water.

Maintenance of quality of polymer solution and chase water for such a long period is a real challenge to the professionals associated with the project and plays a key role for the success of the polymer injection project. For this, continuous surveillance of the entire process is required to ensure effectiveness of the project and take mid course correction, if required. The different monitoring aspects involve in the process are-a) performance of producers, b) rheology of polymer at different points of injection system, c) water quality and other parameters affecting the polymer viscosity, such as dissolved oxygen, bacterial activity and d) injection well rate, pressure and performance.

This paper aims to present main practices followed for maintaining the quality of injection polymer/chase water and other process parameters and to show how it has helped to improve the efficiency and effectiveness of the polymer IOR technique in Sanand field.
Optimized Hydrualic Fracturing for the Gandhar Field
Authors: Sagar Rajiv , Pandey A. K. , Prasad Durga , Vinod A. K. , Panse Rohit , Nugraha Ikhsan , Taneja Pankaj
Published: March 2008

Gandhar is one of ONGC's major brownfields, discovered in 1983 and located in Gujarat. The Field produces approximately 30,000 bopd and is on decline.

A joint team from ONGC and Schlumberger carried out a rigorous process of candidate selection, fracture design, and implementation of fit-for-purpose technologies.

10 candidate wells were selected and the target zone was the GS-3A reservoir. 10-15ft above the GS-3A was a water bearing sand. Most of the candidate wells were primarily in an area of the reservoir that had experienced poor recovery primarily because of poor permeability.

There were unique challenges posed by the Gandhar candidate wells. Earlier attempts to fracture wells had been unsuccessful. In addition the water bearing sand posed a risk to successful execution; the fracture had to be contained within the zone of interest. High Pressure and high temperature operations posed additional challenges that had to be addressed.

For Fracture containment Schlumberger's Sonic Scanner tool provided rock mechanical stress data that was used to design the fracture to be contained within the zone of interest and not break into the water bearing sand above. It also provided the maximum stress direction to determine the preferred orientation plane for perforating. Oriented perforating assisted in achieving lower fracture breakdown pressures.

Fracturing fluids for high temperature (320 degF) operations were selected. Well design and equipment was considered for high pressure operations (10,000 psi surface pressure)

Using this process, 10 wells were successfully hydraulically fractured. Unfortunately, wells produced lower than expected; unforeseen in-situ emulsions are suspected as the cause for the production impairment.

In this paper we will describe the technology and processes brought to the project. Current results and impairment issues will also be presented.
New Completion Technology As A Catalyst to Improve Oil Recovery
Authors: El-Abd Salem , Amiri Abdel Hameed , Keshka Ashraf , Al-Bakr Salem , Al Arfi Saif , El-Asmar Magdi
Published: March 2008

This paper presents the reservoir considerations, implementation and results of a new completion technology with the aim to improve ultimate recovery. The non-uniform production profile across the horizontal hole especially in the highly heterogeneous and fractured reservoirs can result in premature water production and lower ultimate recovery. PLT surveys were carried out in some horizontal wells which indicated non-uniform production profile across the horizontal holes. Therefore the need for production system as part of the completion was raised to control water production and to improve ultimate recovery. This completion technique will the low and high permeability intervals to contribute to flow was found to be the optimum option for this highly heterogeneous and fractured reservoir.

Horizontal hole segmentation using ICD (Inflow Control Device) completion was found to be the optimum option to be tested as pilot in a new and an existing wells. The new well was expected to penetrate highly fractured area and the existing well is also located in highly fractured area.

The ICD Equalizer system was installed in both wells to evaluate the technique. The surface testing results of the re-completed well indicated a drop in the well water cut from 7% to traces. PLT survey was carried out in both wells and indicated uniform production profile across the horizontal section. Therefore the reliability of the technique was proved and these jobs were considered as the first application in United Arab Emirates. With field scale implementation, the reservoir simulation and economic analysis revealed an improved oil recovery of 1% and higher NPV.
Integrated Permeability Modeling Using Wireline Logs, Core and DST Data in a Deepwater Reservoir
Authors: Taware Satyajit , Taware Anuradha , Sinha Amit , Jamkhindikar Atul , Talukdar Ramen , Datta-Gupta Akhil
Published: March 2008

Reservoir characterization requires accurate estimates of permeability. The commonly used porosity-permeability transforms are often inadequate as permeability is also a function of clay distribution, sorting, pore connectivity, tortuosity and variations in other petrophysical properties. More robust permeability estimation can be made by integrating multiple logs in the transform instead of just porosity.

This paper deals with a novel technique for deriving permeability by correlating multiple well logs with core permeability using non-parametric regression methods. First, we classify the well log data into electrofacies based on the ‘similarity’ of their response. This electrofacies classification does not require any artificial subdivision of the data population but follows naturally based on the unique data values reflecting minerals and lithofacies. A combination of principal component and model-based cluster analysis are used to characterize the electrofacies. Secondly, we apply a non-parametric regression technique to predict permeability using well logs within each electrofacies. The main advantage of this technique is that it is primarily data-driven as opposed to model driven and does not require a priori specification of functional forms, which makes conventional multiple regressions difficult and often biased.

The proposed technique was used in a deepwater reservoir system consisting of thick massive sand beds along with thinly bedded sand-shale sequences. The work flow consists of electrofacies identification, facies-wise permeability transform generation, calibration with DST data, and finally permeability population in the geological model using cloud transforms and Sequential Gaussian Simulation (SGS). The permeability transforms generated from core and well log data were validated via blind tests whereby we predicted permeability in another cored well that was not included in the correlation. For further validation, we also used the transform-derived permeabilities in analyzing the DST results in a blind well where a laminated sand section was tested. A reasonable match of the permeability-thickness product was observed. Finally, the permeability transforms were integrated into a 3-D geologic modeling using SGS and cloud transform. It was observed that our approach correctly captured the porosity-permeability scatter in the geologic model for various facies groups.
A New Method for Gas Well Deliverability Potential Estimation Using MiniDST and Single Well Modeling: Theory and Examples
Authors: Kumar N. Karthik , Joshi Sameer , Banerjee Raj , Sundaram K. M.
Published: March 2008

This paper presents techniques for interpretation of MiniDrill Stem Test (MiniDST) for establishing commingled Absolute Openhole Flow Potential (AOFP) in deep water exploration wells in India. These gas bearing reservoirs are vertically heterogeneous with high permeability.

MiniDST's are conducted using the inflatable straddle packer system of wireline formation tester. A MiniDST transient sequence consists of a single or multiple flow periods, induced using a downhole pump, followed by a pressure buildup. The objectives of a MiniDST are sampling, estimation of reservoir properties such as permeability (k), skin(s), radial extrapolated pressure (p*) and estimating AOFP. AOFP is an important gas well flow parameter and is used to determine the commerciality of discovered prospects. We use a two step approach in establishing commingled AOFP of gas wells. First, we conduct a multiple station MiniDST run and interpret the data to estimate reservoir parameters (k, s, and p*). We also compute non-Darcy flow coefficient (D) using Swift & Kiel expression and then use an analytical pseudo-steady state equation to establish single point AOFP for each of the tested zones. Second, we extend routine forward modeling and incorporate features such as scaled permeability data, rock types and hydraulic flow units through interpretation of Nuclear Magnetic Resonance (NMR) and wireline petrophysics, into a model. The model is built in two different ways. One is based on numerical simulator and another based on cumulative permeability-thickness product for the gas bearing zones, using average reservoir pressure and temperature for the whole zone of interest. The success of single well simulation has given us the capability to forecast total AOFP for multiple zones using commingled approach. Furthermore, we also included production tubular and choke in our simulation model for well deliverability estimation.

Our technique has resulted in immense saving in rig time and cost since the workflow allowed delivering answers which enabled us to determine AOFP without resorting to conventional four points deliverability testing.
Design Tapered Electric Submersible Pumps For Gassy Wells
Authors: Zhou Desheng , Sachdeva Rajesh
Published: March 2008

A tapered electric submersible pump (ESP) is mainly used to pump wells with high gas oil ratio. Free gas is separated and vented via a shroud or gas separator. Or, it is compressed using a tapered larger-than-normal pump or specially-designed gas handler below the "normal" pump. Although tapered ESP has been used for decades in petroleum production, few articles have discussed its design. After studying the pressures and flow rates stage by stage using a computer program, the paper presents basic criterion to design a tapered pump.

Free gas in pumped fluid stream reduces pump performance, and may cause surging and gas lock. For tapered pumps the free gas effect becomes vital since generally tapered pumps handle considerable amount of free gas. The paper discusses traditional homogeneous model and multiphase pumping model. By comparing pump performances of the two models using examples, the paper presents that the traditional model designs fewer stages and will produce smaller rate than desired rate. Further, without considering free gas effect, the pump above bottom pump may work out of its operating range. For a tapered pump, pumping stability should be checked and pump degradation should be included in stage by stage calculation. Also, fluid flow pattern should be checked to avoid slug flow at the place of pump intake.

Also presented are optimal design methods for both single and tapered pumps. Widely used design methods are using desired liquid rate at surface or the liquid rate at pump intake to select a pump with closest best efficiency point. The paper illustrates by examples that the two liquid rate methods fail to design high efficiency when pumping high gas/liquid fluid, and proposes two methods of using total rate at pump discharge and using average total rate. The two design methods will improve a well's pumping efficiency and running life.
Intergenerational Mobility in Australia
Authors: Leigh Andrew
Published: March 2008

Combining four surveys conducted over a forty year period, I calculate intergenerational earnings elasticities for Australia, using predicted earnings in parents' occupations as a proxy for actual parental earnings. In the most recent survey, the elasticity of sons' wages with respect to fathers' wages is around 0.2. Comparing this estimate with earlier surveys, I find little evidence that intergenerational mobility in Australia has significantly risen or fallen over time. Applying the same methodology to United States data, I find that Australian society exhibits more intergenerational mobility than the United States. My method appears to slightly overstate the degree of intergenerational mobility; if the true intergenerational earnings elasticity in the United States is 0.40.6 (as recent studies have suggested), then the intergenerational earnings elasticity in Australia is probably around 0.20.3.
A Microsphere-Based Vaccine Prevents and Reverses New-Onset Autoimmune Diabetes
Authors: Phillips Brett , Nylander Karen , Harnaha Jo , Machen Jennifer , Lakomy Robert , Styche Alexis , Gillis Kimberly , Brown Larry , Lafreniere Debra , Gallo Michael , Knox Janet , Hogeland Kenneth , Trucco Massimo , Giannoukakis Nick
Published: March 2008

OBJECTIVE—This study was aimed at ascertaining the efficacy of antisense oligonucleotide-formulated microspheres to prevent type 1 diabetes and to reverse new-onset disease.

RESEARCH DESIGN AND METHODS—Microspheres carrying antisense oligonucleotides to CD40, CD80, and CD86 were delivered into NOD mice. Glycemia was monitored to determine disease prevention and reversal. In recipients that remained and/or became diabetes free, spleen and lymph node T-cells were enriched to determine the prevalence of Foxp3+ putative regulatory T-cells (Treg cells). Splenocytes from diabetes-free microsphere-treated recipients were adoptively cotransferred with splenocytes from diabetic NOD mice into NOD-scid recipients. Live-animal in vivo imaging measured the microsphere accumulation pattern. To rule out nonspecific systemic immunosuppression, splenocytes from successfully treated recipients were pulsed with β-cell antigen or ovalbumin or cocultured with allogeneic splenocytes.

RESULTS—The microspheres prevented type 1 diabetes and, most importantly, exhibited a capacity to reverse clinical hyperglycemia, suggesting reversal of new-onset disease. The microspheres augmented Foxp3+ Treg cells and induced hyporesponsiveness to NOD-derived pancreatic β-cell antigen, without compromising global immune responses to alloantigens and nominal antigens. T-cells from successfully treated mice suppressed adoptive transfer of disease by diabetogenic splenocytes into secondary immunodeficient recipients. Finally, microspheres accumulated within the pancreas and the spleen after either intraperitoneal or subcutaneous injection. Dendritic cells from spleen of the microsphere-treated mice exhibit decreased cell surface CD40, CD80, and CD86.

CONCLUSIONS—This novel microsphere formulation represents the first diabetes-suppressive and reversing nucleic acid vaccine that confers an immunoregulatory phenotype to endogenous dendritic cells.
Genetic Variants of FTO Influence Adiposity, Insulin Sensitivity, Leptin Levels, and Resting Metabolic Rate in the Quebec Family Study
Authors: Do Ron , Bailey Swneke D. , Desbiens Katia , Belisle Alexandre , Montpetit Alexandre , Bouchard Claude , Pérusse Louis , Vohl Marie-Claude , Engert James C.
Published: March 2008

OBJECTIVE—A genome-wide association study conducted by the Wellcome Trust Case Control Consortium recently associated single nucleotide polymorphisms (SNPs) in the FTO (fatso/fat mass and obesity associated) gene with type 2 diabetes. These associations were shown to be mediated by obesity. Other research groups found similar results in Europeans and Hispanics but not African Americans. The mechanism by which FTO influences obesity and type 2 diabetes is currently unknown. The present study investigated the role of two FTO SNPs (rs17817449 and rs1421085) in adiposity, insulin sensitivity, and body weight regulation, including energy intake and expenditure.

RESEARCH DESIGN AND METHODS—We genotyped 908 individuals from the Quebec City metropolitan area that participated in the Quebec Family Study, a long-term study of extensively phenotyped individuals designed to investigate factors involved in adiposity.

RESULTS—We found significant associations for both SNPs with several obesity-related phenotypes. In particular, rs17817449 was associated with BMI (P = 0.0014), weight (P = 0.0059), and waist circumference (P = 0.0021) under an additive model. In addition, this FTO SNP influenced fasting insulin (P = 0.011), homeostasis model assessment of insulin resistance (P = 0.038), and an insulin sensitivity index derived from an oral glucose tolerance test (P = 0.0091). Associations were also found with resting metabolic rate (RMR) (P = 0.042) and plasma leptin levels (P = 0.036). Adjustment for BMI abolished the associations with insulin sensitivity, RMR, and plasma leptin levels.

CONCLUSIONS—These results confirm that genetic variation at the FTO locus contributes to the etiology of obesity, insulin resistance, and increased plasma leptin levels.