bluuebunny/crossref_metadata_2025_split huggingface dataset:
New PDC Technology Saves Operator $4.7 Million Drilling Challenging 8-1/2" Directional Hole Section
Authors: Al-Suwaidi Abdullah S. , Soliman Ahmed Abou , Zeinoun Klink , Isbell Matt , Dykstra Mark , Jones Christopher , Hoss Parham 
Published: December 2007

Abstract
Roller cone bits have dominated the 8-1/2" steerable application in Abu Dhabi due to their proficient steerability, consistently achieving the required build rates in the soft Nahr Umr shale. In the vertical section, PDC bits often achieve up to four times the penetration rates of TCI bits. However, directional performance when using PDC bits to build angle was compromised by fluctuations in reactive torque resulting in poor tool face control and inconsistent build up rates. The overall result was poor penetration rate and performance compared to roller cone bits. The operator and a service company utilized a new design process and cross functional team approach to aggressively seek new steerable PDC technology to drill the curved section with controllable torque response and consistent directional behavior while achieving the full penetration rate advantage of PDC bits. This process was complemented by the Well Delivery Limit process (WDL) that was already established by the operator that focused on delivering high value wells with significantly reduced costs. The team analyzed the drilling operations from virtually every perspective using numerical models, laboratory drilling tests, and field testing. The key to the PDC solution was the team process that identified the relevant drilling problems and performance requirements in order to develop the needed technology. After 72 bit runs from November 2001 to December 2002, the team reduced drilling costs by $39.21 per foot for a total savings of $4,780,530 over 121,916 ft and 3227 drilling hours. The average ROP for the section doubled from 18 ft/hr with TCI bits to 37.78 ft/hr. The current ROP record stands at 60 ft/hr over a 3,169 ft interval.
A Simplified Hole Cleaning Solution to Deviated and Horizontal Wells
Authors: Bizanti M. S. , Alkafeef S. F. 
Published: December 2007

Abstract
Well bore bottom hole cleaning is an essential problem to be recognized when drilling oil or gas wells. Poor or under designed well hydraulics will lead to poor bottom hole cleaning. Slip velocity correlation&#39;s have been developed in the past fifty years and recommendations of proper annular velocities have been suggested in order to prevent slippage of drill cuttings around drill collars and around the drill bit which in turn lead to regrinding of these cuttings causing a waste of the limited energy available to the drill bit. An average annular velocity of 80-120 ft/min has been seen in the oil industry to satisfy the criteria of the proper well bore cleaning.
Drill cuttings transport in deviated and horizontal wells has been examined in the laboratories and factors effecting cutting bed forming have been examined previously. In this paper a simple method predicting the minimum mud pump flow rate required to lift cuttings in a deviated holes and horizontal sections is proposed. The variables required in determining the minimum flow rate are: hole diameter, angle of deviation, plastic fluid viscosity, yield point, mud weight, cutting specific gravity, and the rate of penetration.
The propsed method was checked against field values and has produced excellent results. The proposed methodology of the hole cleaning in the deviated and the horizontal wells can be utilized as a quick tool in future hydraulic designs.
An Effective Means to Control Lost Circulation in Flowing HPHT Wells- Case History from East Med Sea Area
Authors: Medhat Sanad , Arshad Waheed 
Published: December 2007

Abstract
High pressure/high temperature (HPHT) wells can present a myriad of challenges including lost circulation, well kicks, underground blowouts, or other mechanical constraints before a final target depth of 12,000 ft or more is reached. Thereafter, the bottomhole environment with temperatures of 300+deg F and pressures exceeding 10,000 psi test the limits of hardware and chemicals. Each operational misjudgment or tool malfunction can impact the well costs significantly. For example, the pipe trip time to correct such problems can run into twelve to twenty four hours of non-productive time.
This paper addresses a well control issue in a HPHT exploration well where a possible underground crossflow was in progress and the well was losing oil-based mud. Several days were spent trying to control the well by using various fluids (some conventional and others new) but with no success. Eventually a new, Wellbore Pressure Containment Improvement System (WPCIS) was implemented, and it controlled the losses effectively. The well had been losing at an ECD (equivalent circulating density) of 16.4 ppg. Application of the WPCIS process improved the wellbore pressure containment (WPC) side of the mud weight window to sustain an equivalent of 17.0 ppg mud as measured by a formation integrity test (FIT). This remarkable WPC improvement was achieved along with several other cost saving factors.
The discussions in this paper will further reveal the workings and applicability of the WPCIS as a process that can help optimize well plans leading to lower costs for drilling fluids, casing design, cementing, and completion equipment.
Permeability Upscaling on Corner-Point Geometry in the Near-Well Region
Authors: Ding Y. 
Published: December 2007

Abstract
In this paper, a technique for upscaling of absolute permeability in the well vicinity on CPG (Corner-Point Geometry) gridblocks is presented. The near-well upscaling procedure is very useful for well performance prediction. It can assure the coherence of well results by using fine grid on coarse grid simulations.
The near-well upscaling procedure is developed for advanced wells in 3D. Transmissibilities are upscaled from Cartesian fine grid issued from a geostatistical to CPG coarse grid used for flow simulations. To overcome the difficulty of complex geometrical intersections between fine gridblocks and coarse gridblocks, three approaches (geometrical approach, numerical approach and topological approach) are proposed and compared for flux upscaling. The topological approach, which needs a topological structure for gridblock regrouping in the vertical direction, seems the most promising. The near-well formation damage, which can be predicted using another numerical model, can also be integrated into the near-well upscaling procedure.
Sand Management by Using Ultrasonic Systems at Deep and Ultra Deepwater Installations
Authors: Aldal Dag A. , Instanes Geir , Dahl Tonje 
Published: December 2007

Abstract
This paper offers an introduction to sand production problems in the petroleum industry and the challenges of overcoming them, including the principles of operation of ultrasonic clamp-on sand monitoring systems and why they should be installed subsea rather than topside. It demonstrates how operators can optimize production by using such systems and discusses the savings involved. A description of a field trial illustrates the difference between a subsea and a topside installation to explain the difference in measurement quality and the risks involved due to sand production. It also focuses on how operators optimize production by means of sand monitoring systems and the resulting savings, using actual figures from sand monitor installations.
The latest developments in sand monitoring systems are presented, including the introduction of a retrofit system that can be installed without any disturbance to production. The paper also discusses the probable future of sand management and monitoring for subsea installations.
The Challenges of Predicting Commingled Production of Rich and Dry Gas Reservoirs of the Saih Rawl Field, Oman
Authors: Al-Marhoon N. , Al-Shidhani S. 
Published: December 2007

Abstract
The Saih Rawl field (SR) is the biggest gas field in Oman, containing condensate rich gas in the Barik sandstone reservoir and dry gas in the deeper Miqrat sandstone reservoir. Production to date was mostly from the Barik reservoir, at which most wells are completed, resulting in the reservoir pressure dropped to a current average of 260 to 470 bar form the initial pressure of 513 bar. Furthermore the layered nature of the reservoirs and the varying hydraulic fracturing of the different units, production from the various units differed significantly resulting in significant vertical differential depletion of the reservoir. The field's CGR (Condensate Gas Ratio) of the Barik reservoir has dropped from 480 m3/MMm3 to 300 m3/MMm3 as a consequence of liquid drop out resulting the Barik reservoir pressure dropping to below the dew point pressure, and the increasing dry gas production from Miqrat reservoir through commingled production from some of the wells.
Well performance in the Saih Rawl field is affected by the flow impairment caused by the condensate dropout, the quality of the placed hydraulic fractures in terms of their efficiency and geometry, and completion type, single reservoir or commingled in the two reservoirs of Barik and Miqrat. This makes predicting well performance a very complex undertaking.
The limited worldwide experience in developing tight gas-condnesate reservoirs possed a genuine challenge for the initial development planning of this field in the mid-1990s. In particular the prediction of the long term production behaviour.
Production of gas/condensate wells in tight reservoirs with liquid drop-out is still one of the most challenging subjects in reservoir engineering today. The Saih Rawl field provides one of the first sets of comprehensive data on this phenomenon. The paper reviews actual reservoir performance in the Saih Rawl field over the first 40 months of its production life. For example, high well declines have been observed (upto 50% per annum), the effect of fluid mixture of the rich and dry gas, resulting from the commingled production, the potential cross-flow of the dry gas to the rich gas as was indicated by condensate production and the well capacity. Dynamic models, calibrated by historic production data, are used to assess these effects and to predict future production performance.
Improved Design & Modification of System Results in Efficient Gas Processing in Offshore Gas Field - A Case History
Authors: Shankar Ravi , Kumar Adesh , Gupta V. P. 
Published: December 2007

Abstract
BXY field is the largest gas field of India, located in offshore, 80 km from Mumbai city. The field is currently producing about 32.5 MMscmd sour gas using two process complexes BXA & BXB. The field was put on production in September 1988, with initial gas production of about 2 MMscmd. The field attained a gas production of 10 MMscmd during 1994 and this was the period when some operational problems were observed at one of the process complexes i.e. BXA.
The sour gas processing at BXA consists of cooling of well stream fluids in shell-tube type well stream coolers, three phase separation of well fluid and finally transportation of gas & condensate to shore terminal at a distance of about 235 km. Initially each complex was designed for lesser capacity which was upgraded to 15 MMscmd in 1995-96 after progression of field development. No problem was observed in BXB complex. However, in BXA complex, the gas processing temperature exceeded the desired temperature of 43°C. This resulted in rising trend of moisture content in sales gas, high consumption of TEG (2-3 times more than normal value) in dehydration unit and increased load on operational staff for monitoring. Frequent failures of pipe & fittings of gas cooling system were observed. Well stream coolers had problem of air locking & cooling water flow across coolers came down to half quantity. Overall, severe operational problems were observed in the plant.
An in-house analysis was carried out to resolve these problems. The analysis of total processing system viz. gas cooling system, gas dehydration system, condensate stabilization system was made. Based on analysis, it was found that gas cooling water system is the bottleneck. The various components including material of construction of various equipment of this unit were analyzed and causes of operational problems resolved. A new cooling water system known as ‘cooling water segregation system’ was conceived, designed and installed at BXA complex & other suitable measures undertaken. These efforts streamlined the operating conditions of plant and are now processing 16.5 MMscmd gas without any problem.
The present paper describes stepwise identification of problems, design, review, installation of newly designed system and other issues to resolve the operational problem in this major processing complex. The improved design on implementation resulted in smooth operations in the plant and is working since then without any problem.
Strategies to Mitigate Corrosion Caused Due to H2S in Wells and Well Fluid Lines of Mumbai Offshore, India
Authors: Mali P. V. , Khanra Amit , Sagar P. K. , Meshram P. N. , Singh R. K. , Johari Anil 
Published: December 2007

Abstract
Present work focuses on mitigation strategies adopted to avoid corrosion due to H2S. This can be best achieved by reducing H2S generation to the maximum possible extent. The work pertains to 135 wells and 26 well-fluid lines located in Mumbai Offshore, India. Reservoir souring and injection water breakthrough in oil wells are prime sources for H2S generation. Injection water treatment with biocides, pigging and biocide treatment for well-fluid lines and periodic monitoring of H2S levels, are found to be effective measures for reducing H2S generation.
Single Well Tests to determine the Efficiency of Alkaline-Surfactant Injection in a highly Oil-Wet Limestone Reservoir
Authors: Zubari Hisham K. , Sivakumar V. C. Babu 
Published: December 2007

Abstract
The Mauddud carbonate reservoir is the main oil producer in Bahrain oilfield that has been undergoing crestal gas injection with natural aquifer support at the flanks. It has been producing since 1932 and currently in a very mature stage. Due to its rocks wettability characteristics (preferentially oil-wet nature), the residual oil left behind gas and water fronts range from 20-70%. One of the potential options to recover portion of this residual oil is through Chemical Flooding possibly Alkaline-Surfactant-Polymer (ASP) flood. A project was hence initiated to investigate its technical and economical feasibility. It was decided to carry out field experiments to gauge the reservoir response through well-bore treatments before proceeding with a full-scale study and field pilot implementation. Initial field-testing on single-well huff-and-puff basis with experimental recipes provides sufficient positive indications for the project to proceed.
The results of these initial tests are presented in this paper.
Effect of Gravity on Waterflooding Performance of Stratified Reservoirs
Authors: El-Khatib Noaman A. F. 
Published: December 2007

Abstract
In this paper, an analytical solution is developed for waterflooding performance of stratified reservoirs with gravitational (bouncy) effects between adjacent layers. The ordering of layers is kept unchanged as obtained from core analysis or well logging or as randomly sampled from a specified distribution (usually a log-normal). Differential equations are obtained and solved for the rate of advance of the displacement fronts in two or three successive layers of decreasing permeability. The locations of the displacement fronts are used to obtain expressions for the time of water breakthrough in the successive layers and oil recovery factor and water cut at the time of breakthrough in the different layers.
The effect of mobility ratio, gravity number and the Dykstra-Parsons coefficient of permeability variation on the performance are investigated. Expressions for pseudo relative permeabilities are also derived. Results from the developed model were compared with those from conventional models that neglect gravity effecys.
Neural Network Prediction Model of Miscible Displacements in Heterogeneous Reservoirs
Authors: Gharbi Ridha B. C. 
Published: December 2007

Abstract
Understanding and predicting the performance of solvent drives and remediation of contaminated aquifers in heterogeneous reservoirs is of great importance to the petroleum and environmental industries. In this paper, a general method to scale flow through heterogeneous reservoirs is presented for a miscible displacement of oil by a solvent. Results show that scaling miscible displacements in a two-dimensional, heterogeneous, anisotropic vertical cross section requires the matching of thirteen dimensionless scaling groups. These groups were derived using a general procedure of inspectional analysis. A detailed numerical sensitivity study was performed to reveal the relationship between the scaling groups and the fractional oil recovery of miscible displacements in heterogeneous reservoirs. This relationship was then mapped using an artificial neural network, which can be used as a quick prediction tool for the fractional oil recovery for any combinations of the scaling groups, thus eliminating the need for the expensive fine-mesh simulations. These results have potential applications in modeling miscible displacements and in the scaling of laboratory displacements to field conditions.
Wettability and Relative Permeability of Lower Cretaceous Carbonate Rock Reservoir, Saudi Arabia
Authors: Okasha T. M. , Funk J. J. , Al-Enezi S. M. 
Published: December 2007

Abstract
Results and discussions in this paper relate to a Lower Cretaceous carbonate reservoir located in southeastern Saudi Arabia. It is a heterogeneous carbonate formation with various facies due to diagenetic alteration of the original rock fabric. The reservoir is large and prolific with mixed-wet characteristics. Because of the economic importance and variety of oil-recovery mechanisms operative or possible in the reservoir, the multi-phase recovery behavior has been extensively studied. Also, various wettability tests were carried out using Amott and USBM methods.
This paper describes the variation in wettability and relative permeability of Lower Cretaceous carbonate reservoir and the multi-phase simulations of the experimental results. It shows that measurements are consistent with recent theories of the relationship between water saturation, relative permeability, and wettability as described by Jadhunadan and Morrow, 1991.1 However, the results indicate that the wettability of the reservoir changes from water-wet low on structure near the oil/water contact to intermediate and/or oil-wet behavior higher on structure. Oil-wetting character increases towards the top of oil column and is correlated to decreasing water saturation. The results revealed that changes in wettability are accompanied by changes in waterflood efficiency and facies of deposition.
SHAYBAH-220: A Maximum Reservoir Contact (MRC) Well and Its Implications for Developing Tight Facies Reservoirs
Authors: Saleri N. G. , Salamy S. P. , Mubarak H. K. , Sadler R. K. , Dossary A. S. , Muraikhi A. J. 
Published: December 2007

Abstract
This paper presents drilling, completion, well performance, and reservoir characterization results of a recently-drilled Maximum Reservoir Contact (MRC) well in the Shaybah Field with a total of eight laterals and an aggregate reservoir contact of 12.3 kms (7.6 miles). The well was drilled as part of a pilot program to evaluate both the practical challenges and the reservoir performance impact of MRC wells.
The results to date on three MRC wells in Shaybah indicate significant gains in well productivities as well as reductions in unit development costs. A useful by-product of MRC drilling is the enhancement achieved in reservoir characterization. These benefits point to MRC wells as disruptive technologies (DTs)1,2 which have far reaching implications for developing tight-facies reservoirs.
Innovative Completion Technology and Contingency Planning Simplify Al-Khalij Completions and Reduce Installation Costs
Authors: Giusti F. Duke , Leschi Pierre 
Published: December 2007

Abstract
Enhanced simplicity and reliability are critical in offshore development because of the increased intervention cost compared to onshore services. Recently, TotalFinaElf E&P Qatar completed 15 wells in the Al-Khalij Field, 135 km northeast of Doha, Qatar. Because of the deviation at which they wished to set the packers, the operator needed a completion method that would eliminate slickline intervention. After considering many completion options, the following equipment was chosen: An interventionless plugging device that would allow testing of the entire tubing string without setting the hydraulic packer, during running of the completion, and would allow setting of the hydraulic packer, when on depth, without slickline or coiled-tubing intervention.Punch-to-release injection packers with the reliability of permanent packers that would provide capability to retrieve the entire completion without conducting costly and potentially damaging milling operations.ESP packers that could be reset to allow repairs at the wellhead without pulling the tubing string to replace the packer.Nippleless lock technology to keep the required number of landing nipples to a minimum while providing the utility to place flow-control devices anywhere in the completion string.
TotalFinaElf Qatar employed the above philosophies in completing their wells. By using interventionless completion philosophies and innovative installation methods, the client saved approximately 16 hours of rig time per well and a minimum of 4 slickline runs into each well to run/retrieve the intervention tools. The equipment also allowed testing of the tubing and provided a barrier while installing the tree. Finally, in addition to reducing cost, the elimination of intervention operations reduced risks to the safety of the personnel, the environment, the equipment, and the well bore.
Based on the success of these operations, TFE is planning to use the same completion design to complete a minimum of 10 wells in Phase 3 of the Al-Khalij project.
This completion system can be used in applications that would benefit from a completion deployment without well intervention to set plugs, test tubing or set a packer.