bluuebunny/crossref_metadata_2025_split huggingface dataset:
Implementation of Middleweight Fluids, between Lightweight Air or Foam Fluids, and Heavyweight Conventional Fluids
Authors: Green Taylor C. 
Published: March 2009

Abstract
Drilling fluid systems resulting in formation pressures between the equivalent of water and the equivalent of air would be useful, but have been difficult to develop. Since the successful field trial in January 2008 (Green, Minnett, Cremer 2008), these "middleweight" drilling fluid systems have been further developed. The original system has been refined, and a second approach has been prepared for field trial. The original system is generally referred to as the low pressure system, since air is mixed with liquid and then flows into the drilling rig mud pump. The second newer system is generally referred to as the high pressure system, because air is mixed with liquid after the liquid has passed through the drilling rig mud pump, just before entering the standpipe.
The drilling fluid is similar for both the low and the high pressure systems. It contains a small amount of polymer, clay and shale inhibitors and an air dispersant. The combination forms a solids free fluid that cleans the hole, keeps the formations stable, lowers equivalent circulating densities compared to conventional fluids, and allows the injected air to readily break out on return to surface. The fluid is not intended to form a filter cake, since filter cakes may result in diminished rates of penetration, and certainly result in higher than necessary pump pressures and equivalent circulating densities.
The low pressure system mixes air in a solids free drilling fluid just before entering the drilling rig mud pump. The first field trial showed that adequate pressure can be easily maintained while mixing air and liquid so that the drilling rig mud pumps can perform efficiently. The first field trial also showed that very small amounts of air volume are required to reduce the equivalent density of the fluid.
The high pressure system injects air into the fluid after it has passed through the mud pump. Higher operating pressures are required, and higher volumes of air can be injected into the fluid. The high pressure system may allow lower equivalent densities than the low pressure system.
Revolutionising the Top Drive for Improved Efficiency and Uptime on a Major International Drilling Contractor's North Sea Rig
Authors: Fraser C. , White G. , DePeuter E. 
Published: March 2009

Abstract
One of the biggest breakthroughs in drilling technology was the top drive first commercialised in the 1970's. The advent of the top drive brought vast time savings: through drillers being able to drill with 90ft. stands; elimination of connections and their impact on circulation and the wellbore; being able to rotate and circulate when tripping out giving the ability to get through tight spots, and much more. Since then, apart from changing from DC motors to AC motors the basic functional design has remained the same, that is, one or two large motors connected to a gearbox, driving a main shaft. A new type of top drive has now been developed with possibilities for significant drilling cost savings due to the improvements in reliability and easier maintenance.
A major drilling contractor who had significant experience using top drives on their rig fleet conducted an analysis of where most of their rig downtime occurred. They found that 40% of all their top drive failures were related to gearbox issues (gears, bearings and seals). Another significant failure was with the motors, particularly on their smaller top drives in their land rig fleet. These types of failures had been expensive for the drilling contractor and the operator with significant frustration, lost drilling time and lost revenue. The problems were exacerbated by top drive manufacturers not having spare parts stocked and service technicians not being readily available. This lead to the drilling contractor taking the decision to help develop a revolutionary, new, direct drive top drive, with less parts, no gearbox and improved motor. These systems have now been field trialed extensively, for a number of years onshore and offshore with significant success by this drilling contractor and others in the USA, Middle East, Russia, North Africa and Australia. The drilling contractor is now half way through a program to replace all the top drives on it's complete fleet of existing and new build rigs (31 land rigs and 31 jack ups) and the first DNV certified 750 ton version has just recently been retrofitted on the Rowan Gorilla V jack up in the North Sea. The rig went on location and the top drive performed satisfactoriy with no downtime on the first well for Total and at the time this paper was being written the well was drilled to 11,368 ft.
Innovative Computer Model Increases Success Rate When Placing Deep Kickoff Plugs in Southern Mexico
Authors: Diaz Lenin Omar , Flores Juan Carlos , Justus Frederico , Pasteris Mathieu , Flamant Nicolas , Milne Art 
Published: March 2009

Abstract
Traditionally, service companies have had to place several consecutive cement plugs to successfully kick off wells deeper than 3,500 meters. Within the scope of integrated projects in Southern Mexico where wells are usually deeper than 5,000 meters, the low success rate for traditional balanced plug cementing has jeopardized operational efficiency and financial results. Several plug failures made it clear that the volumetric calculations and other known engineering best practices that were implemented were not sufficient to bring the success rate to an acceptable level. In our field study, we implemented an innovative simulation and design method that allows for engineered optimization of the plug placement design and that shows how a 100% success rate in plug cementing can be achieved in wells as deep as 5,720 meters, with hard formations and an OBM environment. The value of this new method resides in a live analysis and display of the fluid interfaces, mixing both while traveling down the pipe and up the annulus and resulting in the output of an estimated top of uncontaminated cement after pulling the pipe out of the hole. The new workflow reveals the effect of each variable affecting the amount of contamination of the cement slurry downhole and gives the engineer the opportunity to optimize the plug placement design before job execution to reach the highest possible top of uncontaminated cement after execution. The results obtained with the new engineering tool and a precise operational field execution has moved the theory of plug placement from the best practice library to the reality of the plug placement operations.
Evolution of Drillable PDC Technology Enables Operator to Safely and Economically Drill South Texas Gas Wells With Casing
Authors: Limbert David , DeGeorge Jarod , Isbell Matt , Doster Mike 
Published: March 2009

Abstract
An operator in South Texas established a casing drilling program in 2002 to address drilling hazards and has since successfully drilled over 200 wells using purpose-built casing drilling rigs. The typical hazards mitigated by casing drilling include lost circulation, tight hole, and depletion. In 2006 and 2007, the operator realized a 15% savings in drilling cost and increased footage drilled per day by 23% utilizing casing drilling technology.
Given their success with casing drilling, the operator was eager to expand use of casing drilling to their traditional drill pipe rigs. This was easily accomplished in the production hole but more complicated in the intermediate hole section. The purpose-built casing drilling rigs used a wireline retrievable bottom hole assembly (BHA) with a pilot assembly and underreamer. This system was proven and reliable, but the wireline retrievable BHAs had several weaknesses. These weaknesses included wireline operation safety, the cost of tools, and underreamer performance. These factors forced the operator to seek an improved solution for this field development.
A cross-functional team from the operator and service company identified the solution as drillable PDC casing bit technology that allowed the drill pipe and the casing drilling rigs to safely, efficiently and economically drill the intermediate hole. The existing drillable PDC casing bit was used primarily for drilling short intervals or for drilling-in liners in relatively soft formations and was not durable enough to drill the entire interval. The authors will detail how the team developed a "heavy-duty" drillable PDC casing bit with a series of test wells to overcome this challenge. This new drillable PDC casing bit allows the operator to improve further drilling in their field development program by enabling casing drilling in the intermediate hole section on their entire fleet of rigs with minimal additional equipment and cost.
Advanced PDC Technologies Deliver Significant Performance Improvements in the Pinedale Anticline Production Interval
Authors: Gent Jonny , Isenhour Jim , Freeman Mark , Hale Matt , Lyons Nick 
Published: March 2009

Abstract
A rigorous engineering and research effort combined with targeted field testing has delivered a new generation of PDC technology. This technology is intended to be utilized for the most technically challenging drilling applications across the globe.
One of the first applications identified for this new technology was at the Pinedale anticline field in Sublette County, Wyoming. At Pinedale, the operator's directionally drilled development wells target interbedded fluvial sandstones and shales of the Lance Pool (Lance and Upper Mesaverde formations).
Due to surface constraints, all wells are drilled directionally from centralized surface pads. To achieve uniform subsurface well-spacing, well trajectory is S-shaped, with all directional work occurring before the pay interval is encountered at approximately 8,500 ft MD. The pay interval is then drilled vertically utilizing 6 1/2-in. PDC bits to approximately 13,400 ft MD, with the final 1,000 ft frequently drilled with diamond-impregnated bits.
The sequence of interbedded fluvial sandstones and shale comprising the Lance Pool presents a difficult drilling environment. The interval is characterized by moderate but erratic unconfined compressive strengths ranging from 10 to 20 ksi exacerbated by high overburden pressures and increased hydrostatic pressures from mud weights exceeding 15 lb/gal to control pore pressure and maintain formation stability. Confining compressive strengths approaching 100 ksi (excluding formation pressures) are not uncommon. These harsh drilling conditions have led to slow penetration rates and short bit runs utilizing conventional PDC designs.
The authors will describe the technologies developed and included in the new PDC bits. These new technologies have reduced the time in this interval by more than 100 hours per well, a 25% improvement over previous designs. With eight rigs running, each rig drilling one well/month, the operator is seeing productivity gains worth 308 days of drilling time over a year's time.
Early Detection of Drilling Conditions Deterioration Using Real-Time Calibration of Computer Models: Field Example from North Sea Drilling Operations
Authors: Cayeux E. , Daireaux B. 
Published: March 2009

Abstract
Abnormal surface torque and hook load values are symptoms of downhole drilling condition deterioration which can result in unexpected situations. Usually, friction tests are performed at regular intervals and rig personnel uses these measurements to monitor trend variations in order to detect possible risk of poor hole cleaning or increased borehole tortuousity. The quality of the detection can vary greatly in function of the work load and experience of the drilling staff. The availability of real-time measurements through data servers make it possible to automate and systemize the monitoring process and therefore trigger alarms before drilling problems really occurs.
This paper presents a computer system used to systematically analyse real-time data in order to monitor downhole conditions. Such a system can utilize much more data than just the above mentioned friction tests, because mechanical, hydraulic and temperature models can calculate predicted hook load and surface torque in any drilling conditions. The numerical models are automatically calibrated (adjustment of drill-pipe linear weight, factors for mechanical and hydraulic friction and heat generation). The evolution of proper calibration factors is used to detect poor downhole conditions. Automatically generated messages are sent to key personnel who can evaluate the potential problems and take necessary actions.
To validate this new methodology, the system has been run on recorded data from three wells on an oil field in the North Sea. A data filtering technique has been developed and applied to solve problems with noisy and erratic real-time signals. With correct input parameters, the system has clearly indicated unexpected measurements several hours before a pack-off problem occurred and therefore proven that the methodology could help in detecting the worsening of downhole drilling conditions.
Availability of large amount of real-time data at the rig site or in onshore drilling centres does not necessarily facilitate the recognition of drilling problems. However, online interpretation systems, as the one described above, can systematically analyze the logged data to detect as early as possible the deterioration of hole conditions during drilling operations and corrective actions can be taken before any major problem has really occurred.
Formation Damage Induced by Formate Drilling Fluids in Gas Bearing Reservoirs: Lab and Field Studies
Authors: Al-Anazi Hamoud A. , Bataweel Mohammed A. , Al-Ansari Adel A. 
Published: March 2009

Abstract
Formate-based drill-in fluid was used for the first time to drill gas wells in Saudi Arabia. Gas wells were completed in sandstone reservoirs where temperature ranges between 270–310° F. Na/K formate mud was used to drill these wells with required mud weight ranges between 88–105 pcf. Thorough experimental studies were conducted to optimize mud formulation to meet drilling operation requirements and to explore possible induced formation damage. Compatibility tests were performed on formate system with formation brine. Corrosivity of formate brine was also studied on tubing alloys (CS and S13Cr) using field drill-in-fluids (DIF) at simulated reservoir conditions. Return permeability studies showed that Na/K formate system resulted in a less damage compared to conventional mud systems. The formate drill fluids gave a high return permeability up to 77% after circulating the corresponding washing fluid. Two damaging mechanisms were identified: external filter cake and potassium chloride precipitation. Compatibility tests indicated that precipitate formed due to mixing of filtrate with formation brine that contains large amount of chloride. Lab tests imply that formate brine had low corrosion rate when the pH of the solution was maintained above 9. On the other hand, the corrosivity of K-formate brine increases in the presence of CO2due to the formation of formic acid. The results of this study were implemented on several gas wells. The first gas well drilled with formate brine, before this study, showed severe corrosion problems in the bottom hole assembly (BHA) due to the ingress of CO2 and gave a very low production rate. These problems were eliminated in the other two gas wells by completing them with super Cr-13 and implementing a developed on-site monitoring of DIF.
Reelwell Drilling Method
Authors: Vestavik Ola , Kerr Scott , Brown Stuart 
Published: March 2009

Abstract
A new drilling method has been developed in a Joint Industry Project, funded by StatoilHydro, Shell and the Research Council of Norway through the Demo2000 programme. The new drilling method has the following features: –New drilling tools and procedures for improved downhole pressure control.–Optional drill-in liner for immediate wellbore isolation.–Potential elimination of lost circulation and hole cleaning problems.
The new drilling method combines Managed Pressure Drilling and liner drilling. The method implies the use of a concentric drill string. A downhole sliding piston is attached to the string and used for improved downhole traction and pressure control. Several full scale drilling trials at the test rig "Ullrigg" in Stavanger have successfully demonstrated the main features of the new concept and its unique possibilities for improved pressure control and drilling performance.
How Continuous Improvement Lead to the Longest Horizontal Well in the World
Authors: Sonowal Kumud , Bennetzen Bjarne , Wong Patrick , Isevcan Erhan 
Published: March 2009

Abstract
Maersk Oil Qatar AS (MOQ) completed drilling the world record BD-04A well in May 2008 offshore Qatar. This was the successful outcome of engineering efforts to increase extended reach capabilities.
MOQ started to develop the Al Shaheen Field offshore Qatar in 1994 with the application of horizontal drilling techniques, pioneered by Maersk Oil & Gas AS in the North Sea. In 1994, 10,220 feet was the longest horizontal length drilled by MOQ. In May 2008 the BD-04A well was completed with a record horizontal length of 35,770 feet. This well also set new world records for both the longest well at 40,320 feet MDRT and the longest along hole departure of 37,956 feet.
The introduction of new techniques has allowed existing constraints to be successfully challenged and overcome. This was achieved through the application of sound engineering principles and continuous optimization during the field development phases.
This case study will review the history, challenges and planning, leading through to the successful drilling of the BD-04A well. The paper will outline the achievements, improved practices and the engineering analysis of field data where key learning points have been shared for future use and applications. It will show that even when constrained by certain limitations such as rig capacity, major step changes can be achieved by optimizing basic operating parameters. In addition to the world record, several other accomplishments have also been achieved in this well as detailed in this paper by using state-of-the-art horizontal drilling technology.
The paper will not only contribute directly to the industry's knowledge base related to improving hydro carbon recovery through extended reach horizontal wells but also set an example of how operating envelopes can be extended by continuously challenging existing practices.
New Riser Design and Technologies for Greater Water Depth and Deeper Drilling Operations
Authors: Persent E. , Guesnon J. , Heitz S. , Averbuch D. 
Published: March 2009

Abstract
IFP has developed innovative technologies to answer the needs expressed by the oil and gas industry that wish to perform drilling operations in deeper water depths, in harsher environments with higher mud density. A new generation of drilling risers is proposed based on a combination of technologies which provide the riser with much higher performances for tension, pressure and dynamics: ■steel / composite hybrid Choke and Kill lines to withstand high pressures■axial load-sharing between the main pipe and the auxiliary lines to improve the riser's mechanical behavior.
A wide riser design parametric study was therefore performed considering 20 operational conditions. Five water depths from 6,000 ft to 14,000 ft and drilling depths in the range of 20,000 ft to 44,000 ft were considered. On the basis of three main operational requirements (riser mass, buoyancy limitations, riser natural period), the operational working envelopes of a new generation of risers were compared to those of conventional risers.
According to the hypotheses of the study, it appears that the current drilling riser technology is generally limited to a 10,000 ft water depth and a 25,000 ft total depth in heavy rock formations. The dynamic behavior of such long risers, their huge mass and the buoyancy that are required to withstand high pressure encountered at greater drilling depths, strongly penalize the use of conventional riser technology beyond these limits.
The paper shows how the HyperStatic Integration (HSI) concept and the hybrid pipe technology significantly extend the operating working envelopes of the riser. They introduce major improvements in the riser design such as: ■a large reduction of the riser mass and of the required buoyancy for riser joints■an improved dynamic behavior which reduces the risk of riser resonance and increases its fatigue life.
These new technologies therefore allow drilling operations in greater water depths, up to 14,000 ft, and deeper total depths beyond 30,000 ft. Since the qualification of hybrid pipes is now well advanced, further work is being carried out to develop and qualify the HyperStatic Integration techniques in order to have the technology ready for industrialization early in the next decade.
Novel Concentric Expandable Stabilizer Results in Increased Penetration Rates and Drilling Efficiency with Reduced Vibration
Authors: Radford Steven , Li Tracy , Jenkins Mark 
Published: March 2009

Abstract
Technological improvements of drilling and reaming methods continue to be evaluated and introduced to the drilling industry. This paper describes recent, controlled testing of new expandable concentric stabilizers and reamers, performed on a full-scale, highly instrumented drill rig.
An inherent problem of drilling and reaming concurrently is that conventional fixed stabilizers run above expandable reamers can be no larger than the pass-through diameter of the restriction above it and thus cannot effectively stabilize the upper BHA, which often results in undesirable vibrations. However, recent controlled tests have been conducted in twin wells drilled from the same casing under a full-scale drilling rig, one well with only a concentric expandable reamer and the other with both expandable stabilizer and reamer. The testing has shown that utilization of this novel stabilizer produces significant gains in performance.
BHA modeling predicted lower bending moments above the reamer when a concentric stabilizer was utilized. The well drilled with the stabilizer above the reamer resulted in higher ROP with lower downhole WOB and up to 35% reduction in drilling mechanical specific energy (MSE), as compared to the well drilled without the expandable stabilizer. The stabilized well had significantly better drilling efficiency, which is attributed to reducing buckling and whirl in the drill pipe and upper BHA, and reduced frictional losses against the borehole wall. Additionally, lower levels of whirl, lateral and stick-slip vibrations were recorded with the new expandable stabilizer.
The paper describes the novel design features of this expandable stabilizer, which are credited with the step-change improvement in drilling efficiency. Monetary savings from increased drilling efficiencies and improved reliability are anticipated for operators and will be discussed in this paper.