bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Core Data in Log Lithology Calibration: Arab-D Reservoir, Abqaiq and Ghawar Fields
Authors: Ma S. M. , Al-Muthana A. S. , Dennis R. N. 
Published: December 2007

Abstract
The Arab-D is the main oil-producing reservoir in the giant Abqaiq and Ghawar fields. Accurately determining its lithology is important for petrophysics, geological modeling, reservoir management, and directional drilling. To determine reservoir lithology, the neutron-density cross-plot method is often used. This method requires end point matrix densities. The most commonly used "standard" values of end point matrix densities are 2.71 g/cm3 for limestone, 2.87 g/cm3 for dolomite, and 2.98 g/cm3 for anhydrite. However, a review of literature indicates that the end point matrix densities are not consistent, particularly for dolomite rocks. Consequently, this study was initiated to determine the end point matrix densities for Arab-D limestone, dolomite, and anhydrite rocks.
Based on core analysis and geological description, 99 core plugs were selected from nine wells in the Abqaiq and Ghawar fields. For these samples, which cover a wide range of porosities and lithologies, the following tests were performed: porosity, plug and powder matrix density, XRD/FTIR mineralogy, elemental chemistry, and thin section petrography. The data were integrated and the following conclusions were made: The measured powder matrix density agrees with matrix densities calculated from XRD/FTIR data and was found to be higher than the measured plug matrix density, due to micro/isolated pores. The measured plug matrix density was therefore calibrated to the powder matrix density and the calibrated plug matrix densities were used in Arab-D log lithology processing. Comparing with "standard" matrix density values, use of Arab-D specific end point matrix densities yields higher log derived dolomite content, which agrees favorably with core geological description lithology.
Geomechanical Factors in the Successful Implementation of Barefoot Horizontal Completions Totaling 100,000 ft Long, Alpine Reservoir, Alaska
Authors: Ramos G. G. , Erwin M. D. , Enderlin M. B. 
Published: December 2007

Abstract
This is a case study of a successful, field-wide implementation of horizontal, barefoot completions in a moderately competent formation - the Alpine Reservoir in Western North Slope, Alaska, Figure 1. A barefoot completion is a borehole without tubular liners and no cemented support - the least costly but riskiest completion strategy. (In this paper, barefoot and unsupported mean the same and are used interchangeably.) The Alpine experience provides a successful example where the benefits of unsupported boreholes outweigh the risks of borehole failure. To date, this aggressive yet simple completion technique has an aggregate length of more than 160,000 ft, all unsupported.
Combined with good drilling practices, the success of barefoot horizontal wells in Alpine is also due to the following petrophysical and geomechanical factors: Consistent reservoir quality within the layerAbsence of shale-breaks in the producing zoneModerate strength in normal fault geotectonic settingLow variability of strengthLinearly elastic behaviorNon-severe, slight weakening when water-saturatedGood permeability retained under post-elastic strains
The Importance of Extended Leak-Off Test Data for Combatting Lost Circulation
Authors: Økland Dag , Gabrielsen Glenn K. , Gjerde Jørn , Koen Sinke , Williams Ernest L. 
Published: December 2007

AbstractLost circulation due to induced fracturing is a costly problem in the petroleum drilling industry. After a discussion of the processes of fracture initiation and propagation, this paper reports a case from the Norne field offshore Norway. A production well suffered lost circulation during drilling at a mud density significantly below what had been perceived as the local fracture gradient.Striking similarities were found between the lost circulation incident and the results of an extended leak-off test that had been performed at the same depth in an offset appraisal well just months earlier. Both datasets indicated that the formation at the relevant depth had a lower-than-prognosed minimum in situ stress, but a high fracture initiation threshold. This additional barrier to lost circulation was irretrievably lost once a fracture had initiated and penetrated a certain distance away from the borehole.Based on this understanding of the nature of the problem, and an updated set of operational constraints, the drilling operation progressed to the prognosed total depth of a well section that could otherwise have been lost. Future wells will be based on an updated set of pore pressure, collapse pressure, minimum stress and fracture pressure gradients that were established after the incident.The case illustrates that the conventional methods of determining the pore pressure and fracture gradient may carry considerable uncertainty.
Microseismic Imaging of Fracture Behavior in Naturally Fractured Reservoirs
Authors: Urbancic T. I. , Maxwell S. C. 
Published: December 2007

Abstract
Microseismic monitoring has been used to image the growth behaviour of hydraulic fractures in the Barnett Shale, Texas1. The Barnett is a naturally fractured shale reservoir, which causes significant variability and complexity in fracture growth during well stimulation operations. Over the past two years, several Barnett treatments have been successfully imaged using microseismicity recorded in realtime during the stimulations. In this paper, we provide examples illustrating how realtime microseismic monitoring can be used to map the complexity and variability of slurry interaction with pre-existing fracture sets during the treatment. In one example, the dynamic spatial and temporal behaviour in microseismicity during a staged treatment procedure was used to vary the hydraulic fracture geometry. The observations described in this paper suggest that realtime microseismic recording and analysis can be used to map hydraulic fracture variability in naturally fractured reservoirs, evaluate the influence of pre-existing fractures on stimulations, and change stimulation procedures in response to observed hydraulic fracture variability.
A Novel Underbalanced Perforating Gun Deployment System Using Production Packer Technology Successfully Completes HP/HT Offshore Horizontal Well in a Single Trip
Authors: Beveridge Martin , Robb Thomas , Herron Steve 
Published: December 2007

AbstractAn innovative completion method was recently used to complete a well in the Skua oil field in the central area of the North Sea. The Skua field is part of the ETAP (Eastern Trough Area Project) and is borderline high-pressure/high-temperature (HP/HT) with a reservoir pressure of 9,350 psi and a reservoir temperature of 307 °F. The initial field development plan was to have one subsea well with a horizontal reservoir section of 2,000 ft to drain the prospect. Production would be tied back to a central processing platform.The completion design for this well had to address several challenges. What method could be selected for sand control in the long horizontal sectionWhat equipment would maintain integrity in near HP/HT well conditionsWhat configuration would allow the completion to be run underbalanced without completion isolation devices.Several completion options were reviewed. A new gun-deployment system based on production packer technology was chosen because it appeared to offer the best option for meeting all the well requirements. The system would also allow the tubing-conveyed perforating (TCP) guns to be recovered if they failed to fire or malfunction.Orientated perforating guns were used to mitigate sand production. The gun system was deployed from a novel polished bore receptacle (PBR) and permanent packer system that allowed for retrieval of the guns should they fail to fire or malfunction after the packer had been set. The polished bore receptacle and hydraulically set permanent packer were designed with the guns hung off the seal assembly of the polished bore receptacle and the tailpipe run through the permanent packer to the TCP guns.A significant feature of the hydraulically set packer-TCP gun deployment system is that it allows contingencies for recovery of the completion and TCP guns from the well in the event of a total or partial perforation misfire. This was a necessary requirement in view of the fact that a long perforation gun string was to be deployed in a high-temperature reservoir where there would be an increased risk of gun failure due to the ambient reservoir conditions.The Skua well was completed with a fully cemented liner. The completion and TCP guns were run, and the well was successfully completed and perforated underbalanced (without an isolation device) in a single trip.
Unlocking the Potential from UKCS Low Deliverability Reservoirs
Authors: Cranfield Colin B , Naylor Peter 
Published: December 2007

Abstract
There are over 300 undeveloped discoveries on the UKCS, estimated to contain aggregate reserves of more than six billion barrels of oil equivalent. A comprehensive survey has identified that low well deliverability is a primary challenge to development of this resource.
Following literature reviews, a series of information-gathering meetings was conducted with both oil companies and service providers. Thirty-five undeveloped discoveries were examined in detail and the knowledge gained was used to design an interactive workshop. This paper summarises information from fourteen companies and identifies barriers associated with low deliverability reservoirs and corresponding solutions. The reserves associated with specific barriers and potential solutions are highlighted.
Undeveloped discoveries with a well deliverability barrier are typically low permeability, thin- or inter-bedded and with uncertain reservoir connectivity. The technical barriers are challenging, but many solutions exist to manage the risks and uncertainties. For example, better-targeted, long and/or multilateral well-bores, hydraulic fracturing, under-balanced drilling and non-damaging drilling and completion fluids all have potential to raise deliverability.
In other cases, solutions are being developed, such as improvements in modeling structurally complex reservoirs and advances in the areas of seismic resolution and prediction of reservoir performance from seismic data.
Non-technical solutions also have an important part to play. An example is where companies form an alliance to strengthen their technical capability and generate a sufficient resource target in an area such as under-balanced drilling. The study found that the drive towards low cost can often be at the expense of adding value. Service providers frequently found that even within the same company, buyers and users have different objectives. Buyers are driven by ‘cost’, whereas users should be driven by ‘value’. There needs to be a shift towards value-based procurement practices, with a re-appraisal of company objectives and internal performance measures. Similarly, more effective contracts are needed which recognise the impact of risk.
The stage is set for a new wave of activity on UKCS developed fields and undeveloped discoveries and a series of recommendations is made to help facilitate their development.
How Routine Reservoir Surveillance with Neural Networks and Simplified Reservoir Models can Convert Data into Information
Authors: de Jonge Gert J , Stundner Michael 
Published: December 2007

Abstract
Current levels of Reservoir Surveillance technology associated with intelligent well completions, such as fibre optics and permanent downhole gauges, create an increasing flow of data.
Conventional routine Reservoir Surveillance tools do not help the knowledge worker anymore to cope with high-frequency real-time data. Overloaded with data handling work, the knowledge worker in our industry is not capable to reveal the great potential inherent in this data.
A radical different work process and new applications of Data Mining technologies are presented to support the industry's next goal – The Smart Field.
A learning Data Mining approach is presented to detect discrepancies from expected trends and patterns. These trends and discrepancies are then translated into business rules to enable the closed-loop control of oil and gas assets.
Lessons learned are presented and necessary future developments are identified.
The Economic Advantages of Managing Data, ONCE!
Authors: Smith Alan H 
Published: December 2007

Abstract
Most data collected by operators in the North Sea is moved from the contractor to the operator, copied for use within the operator and then copied again to partners. Some data is stored to meet regulatory requirements and/or delivered to the regulator. The consequence of this multifaceted life of the data is the same data is available in many locations with an ever-increasing probability of alteration and corruption as more and more people use it. The net result is a significant amount of avoidable time, and money, spent on copying and data quality control as the same data moves to and fro.
The estimated savings available in the UKCS from managing data ONCE! are of the order of £1.5 billion per annum, or about US$1 per barrel. Realizing these savings would enable vital increased recovery in the North Sea, and beyond.
Managing data ONCE! employs a set of principles, which, when applied will result in the realisation of these practical savings. The principles are: One time data managementNew ways of workingConsistent and correct dataEconomic and efficient
Usage of this principle set achieves value delivery to the operator, partners, and industry as a whole.
One time data management results in a New way of working that delivers Consistent and correct data. The Economic efficiencies achieved through reliable data being managed once, with secure storage and access availability, translate into significant cost savings!
Just as poor management of data can have a significant effect on the bottom line profitability. Placing a cost on managing data ONCE! and employing best practice data management is a key economic advantage.
Full Field Tertiary Gas Injection: A Case History Offshore Abu Dhabi
Authors: Bonnin E. , Levallois B. , Joffroy G. 
Published: December 2007

Abstract
In 1997, a full field non-miscible tertiary gas injection scheme was implemented offshore Abu Dhabi. The purpose of the project was to enhance the oil recovery of a mature carbonate reservoir, in a field located on the border between U.A.E. and Iran.
Analysis of the pilots and early stages of the full field development were extensively described by Stofferis1 and Nicolle2. The present paper focuses on the practical problems encountered and the solutions developed to tackle and efficiently manage this challenging project.
The observed reservoir response to tertiary gas injection is first described at the well level and the main macroscopic parameters controlling this response are presented. The impact of the constraints linked to the surface facilities is then introduced and the overall field gas management policy explained. Finally, almost halfway through the designed project life, a technical and economical assessment is also presented together with the future project extensions.
Nuclear Magnetic Resonance NMR, A Valuable Tool for Tar Detection in a Carbonate Formation of Abu Dhabi
Authors: Najia Walid , Shaban Mohammad , Gossa Hedhili , Ferraris Paolo , Vissapragada Badarinadh , Petricola Mario , Namboodri K. M. N. 
Published: December 2007

Abstract
During the geological history, water borne bacteria may react with oil and result in the formation of tar (synonymous of bitumen in this paper). The dynamics of the reservoir over its history may also leave some tar within the hydrocarbon zones. Tar occupies a portion of the pores and may plug partially or fully the pore throats, significantly affecting the fluid flow in the reservoir. Detection of tar is of high significance in the field development for understanding the recovery and effectiveness of water/gas injection.
Tar can be easily identified in the water zones using the resistivity response. In the oil zone, it is difficult to separate tar and hydrocarbons by using exclusively a resistivity log. NMR transverse T2 relaxation contains useful petrophysical and geological information. The T2 histogram is a function of both fluid properties and pore size distribution. Tar is almost solid and the hydrogen it contains relaxes very fast because of its strong binding forces. The shortened T2 in the presence of tar results in lower NMR porosity, compared to the conventional Density-Neutron porosity. The missing porosity from NMR along with other conventional logs and wireline formation tester can be reliably used in the evaluation of tar in the formation. The results can be quantified with confidence after calibrating with core results.
Two examples are presented from the carbonate formations of Abu Dhabi, in the Middle East, where tar evaluation was successfully performed using NMR, Density-Neutron and MDT data.
An Advanced Method of Determining Insitu Reservoir Stresses: Wireline Conveyed Micro-Fracturing
Authors: Carnegie A , Thomas M , Efnik MS , Hamawi M , Akbar M , Burton M 
Published: December 2007

Abstract
Interest is rapidly growing in obtaining reservoir geomechanical data such as insitu stresses and rock strengths, since it is now realized that they are important to a wide range of applications; from bore hole stability, through to well stimulation and reservoir management issues such as optimal placement of water injectors and oil producers. Reservoir stress magnitudes can be inferred by continuous logs, for example by sonic based measurements. But these must be calibrated to direct measurements of stress. At present the only reliable, accurate measurements of insitu stress come from micro-fracturing. Following an introduction to geo-mechanical effects on limestone reservoirs, the paper focuses on a micro-fracturing technique, based on the Modular Dynamics Tester, MDT*, which efficiently and economically yields high quality stress information. The theory and application of micro-fracturing with the MDT* will be illustrated by an example in which reliable estimates of stress magnitudes, and lower bounds of rock tensile strengths, were obtained in an onshore Abu Dhabi limestone reservoir. This is the first published example of any stress test which has been performed by micro-fracturing in a limestone reservoir. To allow an understanding of the feasibility of the technique in limestone reservoirs, current best practice guidelines for planning and running MDT* minifracs will be summarised. This will include recommendations on how the MDT* can be combined with sonic, imaging and caliper logs to gain other valuable stress related data, such as principle horizontal stress directions, and continuous depth vs stress profiles (minifrac can only give point wise data).
An Integrated Workflow to Account for Multi-Scale Fractures in Reservoir Simulation Models: Implementation and Benefits
Authors: Bourbiaux Bernard , Basquet Rémy , Cacas Marie-Christine , Daniel Jean-Marc , Sarda Sylvain 
Published: December 2007

Abstract
The recent years have seen the emergence of detailed field data acquisition and efficient modelling tools to characterize reservoirs and model their complex internal structure in a realistic way. This progress led to the detection of multi-scale fractures in most reservoirs, and enabled to interpret unexpected field production features such as early breakthroughs. Therefore, the availability of a workflow and an integrated modelling methodology becomes more and more crucial to take into account the geological information about fractures/faults into the reservoir dynamic simulation process for optimizing field productivity and reserves. This paper reviews and illustrates the overall methodology and the specifically-involved procedures and tools we have gradually built from the experience acquired in various fractured field case studies.
The main steps of this multidisciplinary approach include (a) the detection, geological analysis and modeling of multi-scale natural fracture network from seismic and well data, (b) its validation and calibration from dynamic field information such as well tests, (c) the choice of an equivalent simulation model applicable at reservoir scale, and its construction thanks to innovative flow up-scaling procedures applied to the realistic model provided by the geologist, (d) the implementation of predictive and numerically-efficient algorithms to represent the physics of flow transfers occurring both at local and large scale during multiphase field production.
Thanks to this consistent workflow, field simulation models remain interpretable in geological terms, which is helpful for subsequent model updating. Thus, specialists in geosciences and reservoir engineers can cooperate in a very effective way to improve the management of fractured reservoirs.
Well Delivery Limit: Two years' experience with a breakthrough drilling performance initiative
Authors: Al-Suwaidi Abdullah , Faure Alban , Mukhalalati Talal , Al Taweel Abdul Rahman , Bamajbour Abdul Rahman , Edwards Clement , Macklin Jonny 
Published: December 2007

Abstract
ADCO and NDC launched its Well Delivery Limit (WDL) initiative in May 2000 to deliver the step change in performance required to meet its business objectives of increasing production capacity and containing technical costs. In partnership with Shell's Drilling The Limit* philosophy, WDL's performance management system challenges the true value of ADCO's well delivery operations, as opposed to simply doing the same things in a faster and cheaper way. Two years into the initiative, WDL has been implemented on all ADCO rigs with great success and new ways of working have been created by breaking down the barriers between departments in addition to those between ADCO and its Contractors.
From an operational perspective, ADCO has reduced well construction time by more than 30% and reduced cost by 8%. In addition to this, substantial improvements in well quality and HSE performance have been achieved, demonstrating the positive impact that WDL has made on ADCO's entire business.
The successes to date have essentially been in the form of time and cost savings, but even more can be gained by applying of the process to the entire well lifecycle. In other words, now that ADCO have learned how to "drill the well right", focus has shifted to the higher-level objective of "drilling the right well right". This next step has already been implemented on new development projects where existing practices have been challenged to ensure that the overall field development objectives are met in an optimal manner.