bluuebunny/crossref_metadata_2025_split huggingface dataset:
Semiphenomenological Model of Hydraulic Fracturing in Granular Media
Authors: Alekseenko Olga 
Published: December 2007

Abstract
Petroleum engineers have faced the problem of hydraulic fracturing in soft rock formations for many years. However, existing programs used with soft rock formations often do not provide satisfactory treatment designs. Difficulties emerge because hydraulic fracturing in soft rock involves development of a plastic zone near the fracture surface, where rocks partly lose their cohesion. This study has developed a more appropriate model for fracture design, which takes into account processes in the plastic zone for the special case of soft rock that is a cohesionless granular impermeable medium.
The real problem of hydraulic fracturing in an elastoplastic medium has been represented in the model as brittle hydraulic fracture growth in a quasielastic medium. The medium resistance to fracture development is determined by variable apparent fracture toughness, which is a function of the fracture length and is found from the analysis of energy dissipation in the plastic zone.
The dependence of the apparent fracture toughness on input parameters and fracture width at the fracturing fluid front has been established. It reflects the specific feature of the granular medium deforming and closes the equation set of the problem. Semianalytic solutions are obtained. First, there is the area of input parameters, where the effect of plasticity on fracture geometry is significant. Secondly, fracture behavior depends on the typical magnitude of friction forces on fracture sides, but it depends also on the fracturing fluid rheology.
This new model of hydraulic fracturing in a granular medium is an improvement over existing models because traditional brittle fracture models do not take into account the specific rheology of soft rocks and poorly predict fracture geometry. Newer elastoplastic models are unclosed because the size of the plastic zone is undefined. Also, they usually are finite element models and cannot be used for the calculation of practical fracture designs because of time limitations.
This work is only the first step toward practical hydraulic fracturing design in soft rock formations. The model is supposed to be developed and validated against experimental results or field data.
Development of a Subsea TTRD Capability West of Shetland
Authors: Johansen Robert , MacLeod Angus 
Published: December 2007

Abstract
This paper describes BP's project to develop a subsea Through Tubing Rotary Drilling (TTRD) capability in its Deep Water Performance Unit (DPU) West of Shetland.
Lower cost access to barrier reserves and small hydrocarbon accumulations are part of a field development strategy to increase recovery factor and maximise total recovery through the application of new technology. A key challenge of this strategy is the unique application of through tubing rotary drilling techniques to the subsea wells in the hostile deep water West of Shetland.
Project activities leading to implementation in 2009 / 2010 are described. It was identified that an integrated project team consisting of key stakeholders managed by BP would deliver the most robust approach to the extreme challenges of Subsea TTRD delivery. In conjunction with the subsea well environment this represents a key difference to contemporary, platform TTRD projects and supported several key activities: Front end engineering design (FEED) involving Drilling Contractor and Subsea Equipment Manufacturer.Development of a Statement of Requirements and description of riser, BOP and control systems to enable TTRD in subsea wells. Interfaces to semi-submersible mobile offshore drillng unit (MODU).Modifications to rig pipe handling system, active pit system and enhancements to kick detection capability.Mitigation of fatigue damage caused by very high currents experienced West of Shetland acting on the riser and resulting in vortex induced vibration.Damage prevention techniques for Subsea Xmas tree, SCSSSV and tubing.Unique well engineering challenges relating to annulus integrity and TTRD in water injection wells.
The key conclusions from FEED are explained and their impact on equipment, techniques and procedures as applied to Subsea TTRD is described.
Reservoir Candidate Screening: The SURE Way to Successful Underbalanced Drilling Projects - Case Study
Authors: Keshka Ashraf , Al Rawahi Ali Salem , Al Murawwi Rashed Abdulla , Al Yaaqeeb Khalid , Qutob Hani , Boutalbi Said , Villatoro Jaime 
Published: December 2007

Abstract
Abu Dhabi National Oil Company (ADNOC) and its group of companies are considering adapting new technologies to ensure that strategic resources are optimally explored, developed and produced during the life cycle of their oil and gas fields. Underbalanced Drilling (UBD) technology, which can achieve these objectives effectively when applied in conjunction with horizontal drilling techniques, is being considered among various options.
Abu Dhabi Company for Onshore Oil Operations-ADCO, decided to pioneer the introduction of the new technology. A systematic scientific approach was applied to screen thirty reservoirs for underbalanced drilling candidacy, in order to identify the best potential candidates from a given portfolio and to ensure a successful pilot application.
The screening process incorporated reservoir, drilling, and operational data with risk analysis into a rigorous expert system aimed at maximizing the value of any UBD operation. The screening process was performed in two phases;
Phase I comprised of:
- Evaluating and ranking thirty reservoirs with respect to their risked probability of being successfully exploited with horizontal underbalanced drilling and completion techniques as opposed to conventional drilling and completion techniques.
- Comparing candidate reservoirs against global database of analogues proven to be suitable with UBD.
- Selecting the best three candidates for the Phase II detailed reservoir damage analysis and productivity forecast.
Phase II comprised of:
- Identifying the formation damage mechanisms that are expected to occur in each of the three reservoirs.
- Comparing underbalanced and overbalanced costs, production rates, projected revenues and net present value.
- Ranking the three candidates for UBD application.
The paper describes the expert system methodology used in the screening process and the results obtained. The detailed economic analysis presented in Phase II of the study would help ADCO determine the benefit that underbalanced drilling could provide compared to competing conventional drilling & completion technologies.
Integrating Advanced Production Logging and Near-Wellbore Modeling in a Maximum-Reservoir-Contact (MRC) Well
Authors: Mubarak S. , Al-Afaleg N. I. , Pham T. R. , Zeybek M. , Soleimani A. 
Published: December 2007

Abstract
This paper presents a methodology for more accurate reservoir characterization with a field example of Maximum Reservoir Contact (MRC) well evaluation using dynamic production logging and near wellbore simulation modeling. Ultimately, once the results of these analyses are input into geological models and field simulators, more accurate answers would be obtained.
The study was initiated to honor advance production logging results in inverse manner and to explain crossflow behavior. MRC well consisted of two lateral and motherbore and production logging results provided contributions of each lateral (3 rates) and crossflow during shut-in (total of 4 rates during survey) and during small choke. These measurements and results suggested that the choke size should be optimized for better production and drainage strategy.
Comprehensive data integration was performed for more accurate modeling, including all production and injection histories of offset wells and drilling history.
Fine unstructured grid refinement was utilized for near wellbore modeling. The multilateral well has been numerically modeled including friction to match production logging results and to obtain horizontal and vertical permeabilities between layers. Crossflow was also reconstructed in a quantitative manner. To the best of our knowledge, this is the first study with actual data honoring flow contributions and capturing such observations. Sensitivities were also carried out for injection and production history on crossflow behavior.
Inflow Profile Control in Horizontal Wells in a Fractured Carbonate Using Swellable Elastomers
Authors: Welling Rudy W. F. , Marketz Franz , Moosa Riyadh , Riyami Noha , Follows Edward J. , de Bruijn Gerbert , Hosny Khalid 
Published: December 2007

Abstract
A fractured carbonate field is developed via Gas Oil Gravity Drainage in the upper layers and water flood in the deeper layers. Due to the injection of gas and water into this fractured reservoir, horizontal wells tend to gas or water out, impairing the matrix drainage process. Different well and reservoir management techniques are used to prevent this from happening or to control the inflow when it happens. One such technique is to segment the bare foot horizontal open hole section with swellable rubbers and create up to 6 discreet zones of inflow, separated by 3 1/2 " tubing. The inflow from each section is currently controlled by a coiled tubing operated sliding sleeve. In the future it is anticipated that control will be done using hydraulically operated sleeves.
Up till November 2006 eight horizontal barefoot oil producers have been re-completed with swellable packers. This paper concentrates on water shut-off and addresses the design, installation risks and mitigation, the impact of zone shut-off on well production performance, and the actions taken to optimize the production of each well by logging the well and shifting the sleeves.
Optimization of High-Pressure, High-Rate (HP/HR) Gas Wells in a Giant Offshore Field
Authors: Benesch J. M. , Gahr J. Z. , Al-Mohsin A. H. , Schmidt M. H. 
Published: December 2007

Abstract
An extensive large bore gas well drilling program is ongoing for the development of Qatar's North Field. This massive offshore carbonate field contains abnormally-pressured natural gas produced from the Khuff reservoir at ~10,000-ft TVD. In the most extensive application of large bore wells in a single field development, this program involves a large number of wells drilled under challenging subsurface conditions. These large bore wells maximize the gas contribution of each well and reduce overall field development costs by minimizing the number of wells and facilities required. Significant design and operational enhancements made during the program have dramatically reduced drilling time and cost without compromising safety or integrity. In addition to reducing drilling time by over 40%, specialized procedures have been developed for managing major challenges including complex lost returns and well control events.
Drilling and Completing Intelligent Multilateral MRC Wells in Haradh Inc-3
Authors: Al-Bani Fahad , Baim Ahmad Shah , Jacob Suresh 
Published: December 2007

Abstract
The Haradh Increment-3 (HRDH Inc-3) development, commissioned in March 2006, has added significant volumes to Saudi Aramco's daily production capacity. The development has 73 wells comprising of 28 water injectors, 13 observation and 32 producers. 28 of the 32 producers are intelligent completions in multilateral wells. The Maximum Reservoir Contact (MRC) wells with multilateral systems improve the reservoir contact while reducing the drawdown on the reservoir. The intelligent completion system allows the inflow from each lateral to be controlled from the surface without well intervention. The combination of the multilateral and intelligent completion system is expected to enhance field recovery by preventing/delaying water coning and improving sweep efficiency. HRDH Inc-3 may be considered as a milestone in the industry where the field development is focused on the "Smart Multilateral Systems"
Application of cutting edge technologies like rotary steerables system (RSS), realtime drilling data transmission, Geosteering, non damaging fluids, multilateral systems and intelligent completions have helped in achieving maximum effective reservoir contact and delivering the wells ahead of schedule.
The producer wells were drilled with three or four laterals depending on the location of the well. Each of the laterals has around 4,000 ft of reservoir contact and the average reservoir contact for each well is over 14,000 ft.
The wells are constructed as Technology Advancement in Multi-Lateral (TAML) Level-2 system where openhole laterals are drilled out of the motherbore that is cased and cemented. The intelligent completion system comprises of pressure and temperature sensors, production packers and hydraulically operated downhole valves that can be controlled from the surface. The downhole valves are placed in the motherbore to control inflow from each lateral.
The paper presents details of the field planning, drilling and completion practices. The challenges faced in drilling and completing these complex multilateral MRC wells within a tight schedule and the important lessons learned will also be covered in the paper
Lubricants Enabled Completion of ERD Well
Authors: Holand Jonny , Kvamme Svein Arne , Omland Tor Henry , Saasen Arild , Taugbøl Knut , Jamth John 
Published: December 2007

Abstract
Lubricants are often added to the completion or drilling fluid, in order to reduce friction between tubular equipment run into the well, and the wall of the well. This paper shows in detail how the addition of a lubricant to an oil based drilling fluid affected the lubricity significantly in the second of two comparable drill pipe runs, resulting in historically low coefficients of friction.
The use of an ultra-low viscosity drilling fluid resulted in a clean metal to metal contact between the casing and the drill pipe, which caused high static friction. The selected lubricant was designed to stick to metal surfaces, and the result showed that the lubricant had a significant effect on both torque and drag forces. In the drilling phase, the apparent static friction factor decreased from 0.23 to 0.13 and the dynamic friction factor from 0.13 to 0.11. Comparing the two 8 ½" sections drilled, the average off-bottom torque was reduced by 25 % after adding this specific lubricant to the drilling fluid.
In selecting the lubricant, different lubricants were tested using a novel laboratory instrument capable of measuring the coefficient of friction at elevated pressure and temperature. These laboratory measurements proved to be consistent with the observed effect of the lubricants in the field.
A Step Change in Openhole Gravelpacking Methodology: Drilling-Fluid Design and Filter-Cake Removal Method
Authors: Law Matthew , Chao George W. , Ab Alim Hafeez , Samuel Elsamma , Ejan Aziz , Hameed Mohsen Abdul , Samuel Mathew 
Published: December 2007

Abstract
The major trend of completion method in offshore reservoirs with sand control requirement is Horizontal Open Hole Gravel Packing (OHGP). Though gravel packing is a proven method to stabilize the well bore, controlling sand and maximizing productivity, it entraps the filtercake formed by the reservoir drilling fluid. This results in low production rate and consequently leads to the requirement of high drawdown pressure. Hence it is imperative that the filter cake be removed uniformly to ensure lower drawdown pressure, and even flow distribution throughout the producing interval of the well.
A review of the completion methodology in poorly sorted unconsolidated sands with high fines content in Brunei also indicates that the situation is not much different from above, demanding to lower production drawdowns while delivering production quotas. The lower drawdown extends the integrity of sand control completion jewelry, reduces water influx, fines migration, and increases recovery factors and reserves. The Brunei Shell Petroleum's (BSP) Tali asset strategy has been driven towards highly deviated wells with Open Hole Gravel Packs. OHGP requires a high quality mud filter cake to be maintained throughout drilling and placement of the gravel pack.
Traditional methods with acid to breakdown filter cake have been proven ineffective as they cause highly conductive wormholes that contribute the majority of production. The acid can also react with sensitive clays in sandstone resulting in secondary and tertiary precipitations. Additionally, acid reacts with the screen metal causing variation in opening tolerances, which is unacceptable for these poorly sorted high fines content sands.
The objective of this paper is to present the results of the application of a clean up fluid containing a chelating agent and an enzyme to dissolve the filter cake formed by the drilling mud. Use of enzyme breaker and chelating agent used in the clean up fluid helps to promote the dissolution of starch and calcium carbonate components used in the drilling fluid mud. Laboratory test procedures, results, field case histories and production results are discussed in detail. Laboratory tests include the effect of this cleaning up fluid on the filter cake formed by different drilling mud composition. Field case histories comprise of the gravel packing of the oil producer well and subsequent treatment with the proposed clean up fluid.
How Much is Left of Your Centralizer After Exiting a Casing Window in an Extended-Reach Horizontal Multilateral? Modeling, Yard Tests, and Field Results from Alaska's West Sak Development
Authors: Peterson E. M. , Greener M. R. , Davis E. R. , Craig D. T. 
Published: December 2007

AbstractThe West Sak viscous oilfield on the North Slope of Alaska is currently being developed with extended reach multilateral wells, with departure to depth ratios up to 5 to 1, in which horizontal slotted liners are utilized in conjunction with a TAML level 3 multilateral junction system. Centralizers are considered necessary on the slotted liners to avoid slot plugging, reduce drag, and limit differential sticking. Selection of proper centralizers to run through a casing exit, without a whipstock in place, has been key to ensuring a successful multilateral installation.Several failures of centralizers run on liners through casing exits have resulted in significant drilling lost time associated with fishing and milling pieces of centralizers in order to place the wells into proper service. After three such failures, the requirement to study the passage of a centralized liner through a casing exit became essential. A surface test fixture was utilized to simulate liners run through a casing exit to test several potential centralizer candidates using the loads estimated from modeling. Torque and drag modeling provided the side force estimates exerted on the liner and centralizer as they passed through a casing exit.This paper will the discuss the liner centralizer installation problems prior to the testing program, detail the modeling used to determine the loads exerted on the centralizer at the casing exit, show the results of the yard tests conducted on several commonly utilized industry centralizers, and make recommendations for proper liner centralization in multilaterals.
Cement Seal Units Eliminate Interzonal Communication
Authors: Elzeghaty S. Z. , Kinzel Holger , Colvard R. L. 
Published: December 2007

Abstract
SEAL UNITS prevent gas/fluid movement at the interface between the outer surface of the casing and the inside of the cement sheath. In spite of the improved practice of releasing pressure on the casing after the top plug bumps, investigations by different research and development groups confirm that leakage at this interface is very possible. When subjected to differential pressures, often encountered in completing or producing a well, inter-zonal communication at this point will occur, like "channeling" in the remainder of the annulus. This will prevent efficient production of the producing zone or cause stimulation work (fracturing, acidizing, etc.) to be ineffective due to uncontrolled fluid migration in the annulus.
Two Salt-Dome Wells Sucessfully Drilled with Casing-While-Drilling Technology
Authors: Veltri David , Warren Tommy , Tessari Robert 
Published: December 2007

Abstract
Recent conventional wells drilled around the Chachaloula Salt Dome field in South Louisiana have been drilled directionally from central pads due to wetland environmental issues. These wells often encounter borehole instability and lost circulation drilling problems. Some take multiple sidetracks to reach the target and others are abandoned before reaching the intended target depth.
Two wells were drilled with Casing while Drilling (CwD) technology in mid-2005 to depths similar to conventionally drilled offset wells. Both wells successfully reached the target formations. The second well delivered a 25% savings based on the average offset cost.
The CwD wells utilized rotary steerable directional technology for deviation control through the steeply dipping beds. Operations conducted through the casing drillstring included a plug-back and sidetrack and two fishing operations for failed downhole tools. These operations were performed without tripping the casing out, thus showing the versatility of the CwD technology.
Utilizing the Effect of Nitrogen To Implement Light-Oil Air Injection in Malaysian Oil Fields
Authors: Mohiuddin Zeeshan , Raja D. M. Anwar , Saaid Ismail Mohd 
Published: December 2007

Abstract
Air injection has been used as one of the enhanced oil recovery (EOR) techniques especially to extract the heavy oil. Nevertheless, a number of applications of in-situ combustion (ISC) for light oil reservoirs have been also reported successful. In light oil reservoirs, the thermal method of EOR is known as light oil air injection (LOAI). This paper discusses the research work carried out to find the potentials of LOAI in Malaysian light oil reservoirs. Screening criteria has been developed from which Dulang E12-14 reservoirs were short listed for further study. In research study, combustion was assumed to occur in low temperature oxidation (LTO) to eliminate the complexities of combustion process. In simulation studies, effect of nitrogen was utilized in place of air, as nitrogen has various common properties with air due to the higher percentage in it. By this assumption, the early potentials of LOAI can be identified without performing experimental studies. This method could provide an easy alternative to assess the potential application of the LOAI technique for depleting Malaysian light oil reservoirs. Experimental studies may need to be carried out if simulation results show the significant amount of incremental oil.
Results of the simulation work seemed to suggest that the LOAI could significantly increase the oil recovery factor from the depleting Malaysian light-oil reservoirs. The EOR screening software PRIze also reflected this trend. Besides this incremental recovery, the volume of produced gas also increased.