bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Unique Experience of the Evolution of the Bit Technology and Application Experience through 20 years of Tunu Field Development, Indonesia
Authors: Yunus Fata , Besson Alain 
Published: December 2007

Abstract
The bit technology has evolved dramatically over the last 20 years through innovative techniques. New bit technologies have also allowed the introduction of improved drilling parameters. In the late seventies, the introduction of PDC bits generated impressive changes in the drilling performance. Later, in the eighties and the nineties, the continuous improvement of the understanding of the fixed cutter bit behavior, and the PDC cutter technology, opened a new era and consistently lead to better results. Alongside these striking events in the PDC bit development, the roller cone bit technology showed significant improvements in both the bearings and the cutting structures.
These results and the evolution of the technology are clearly illustrated in the bit performance experienced in the TUNU field, Indonesia. Over 200 wells have been drilled on TUNU since the exploration began in the mid seventies. Innovative designs were used for the optimization of the performance, the latest proven technologies were applied successfully. Over the past two decades, bit related performance has improved almost 10 times in the TUNU field.
The lithology of the TUNU field at the top of the intermediate section consists of soft to very soft, sand and Claystone. Through this section the hydraulic behavior of the bits was a key factor affecting their performance.
Below this zone, the formation is composed of medium strength sandstone and shale. Very hard dense dolomite and limestone stringers are encountered erratically throughout the interval. A high level of vibration, leading to catastrophic failures was typically observed throughout this zone.
The first roller cone bits run in TUNU gave run lengths no greater than 250 m, and an average ROP never exceeding 6 m/h. In the early eighties, the introduction of the first PDC bits led to spectacular results where more than 250% gains in ROP and meterage were achieved. In the early nineties, roller cone bits fitted with metal face seal and new cutting structures allowed, for a short while, to see roller cone bits drilling at lower cost than PDC bits. The first anti-whirl bits tripled the run length and doubled the ROP. Later, successful runs of steel body unbalanced bits provided an additional gain of 20% in the performance. Today, force balanced steel body PDC bits indicate that drilling this section with one bit and an average penetration rate of 45 m/hr is a reality.
Globally, the average penetration rate and meterage drilled per well improved almost by eight times and the trip time was also reduced drastically. In the intermediate section, the total saving per well is close to 1,000,000 US$. The cost per meter has dropped from 470 $/m to around 70 $/m. For the field, through the various phases of drilling, when comparing the performance of the first wells, and thanks to a continuous and active engineering follow up, more than 80 M$ were saved.
Innovative Low-Friction Coating Reduces PDC Balling and Doubles ROP Drilling Shales with WBM
Authors: Mat M. Rujhan , Zakaria Mohd Zulkifi Bin , Radford Steve , Eckstrom Darren 
Published: December 2007

Abstract
This paper describes the successful development and application of a new low-friction flouropolymer-based coating applied to PDC bits to minimize and often prevent balling while drilling shale formations. Successful laboratory testing, the results of several field runs and one field case study will be presented. The rate of penetration is shown to more than double in certain cases resulting in significant savings to the operator.
Unique Crosslinking Pill in Tandem with Fracture Prediction Model Cures Circulation Losses in Deepwater Gulf of Mexico
Authors: Caughron Douglas E. , Renfrow Douglas K. , Bruton James R. , Ivan Catalin D. , Broussard Paul N. , Bratton Tom R. , Standifird William B. 
Published: December 2007

Abstract
Even in routine applications, the safety, economic and technical problems associated with lost circulation can severely impact drilling operations. The negative consequences are magnified greatly in the deepwater environment. Dramatic reduction in penetration rate and the downtime spent regaining circulation can further escalate already high operating costs. More importantly, the well control issues surrounding lost circulation pose critical safety concerns.
In many of these wells, merely identifying the thief zone or zones is a major technical challenge. Furthermore, once identified, the vugs and fractures in the loss zones are at times too large to be bridged with conventional lost circulation material. This paper describes the development of a uniquely engineered lost circulation pill that when used in tandem with new real-time geomechanical analysis methods and pill formulation software, cured severe losses in the deepwater Gulf of Mexico.
The authors will describe the development and laboratory modeling used in producing the specialized and chemically activated cross-linked pills, engineered to stop whole drilling fluid losses. As detailed in the paper, the pill proved to be far superior to conventional lost circulation material. Further, the paper will discuss its application in a well drilled in more than 2,800 ft of water in the Gulf of Mexico, which had encountered losses of up to 2,000 bbl of synthetic-base drilling fluid. The 100-bbl pill was formulated using a specialized software package. This was used in combination with a new process for analyzing the location, and extension pressure of the drilling induced hydraulic fracture using resistivity and annular pressure measurements. Once the pill was placed across the fracture zones, squeezed and later drilled out, normal drilling resumed with pre-fracture parameters resulting in penetration rates in excess of 50 ft/hr with no further losses.
In addition to discussing the development and application, the authors will outline the lessons learned on the deepwater project featuring pre-planning issues geared toward ensuring circulation is maintained throughout the wellbore.
Reservoir Limit Testing For Fractured Wells
Authors: Gringarten Alain C. 
Published: December 2007

ABSTRACT
The purpose of the paper is to extend reservoir limit test analysis techniques to fractured wells. By deriving the pseudo-steady state pressure functions for an unfractured and a fractured well at any position of a closed rectangle, it is shown that shape factors for fractured wells are not readily obtainable from the ones for unfractured wells.
Exact analytical expressions of shape factors for fractured and unfractured wells in a closed rectangle are presented, along with graphs of these quantities versus appropriate parameters.
Type curves for a fractured well at the center of a closed rectangle are also provided. Both uniform flux and infinite conductivity fractures are considered.
The curves presented in this paper are then used with actual field data for estimating the drainage volume of a fractured well and the shape of the well drainage area.

INTRODUCTION
Reservoir limit tests, introduced by Jones1, are commonly used for evaluating the reservoir volume communicating with the well. The analysis is based on the fact that the well pressure during pseudo-steady state flow is a linear function of the production time:Equation 1
whereEquation 2
andEquation 3
A represents the drainage area (in sq.ft) and CA the drainage area shape factor. Eq. 1 may also written in dimensionless form as:Equation 4
withEquation 5
andEquation 6
A cartesian plot of bottom-hole flowing pressure versus production time will thus yield a straight line after pseudo-steady state conditions are reached. The slope of the straight line (Eq.2) may be used to estimate the connected reservoir drainage volume:Equation 7
and the drainage area, if Ï?h is known.
The shape of the drainage area may be estimated from the pseudo-steady state cartesian plot if pressure data are also available from an infinite acting flow period2. These are used to determine the semi-log straight line slope:Equation 8
and p1hr. The system shape factor is then obtained from:Equation 9
By comparing the calculated CA with the ones published in the literature for various drainage area configuration3–5, it is possible to estimate the shape of the drainage area.
Systematic Team Approach to Drilling Optimization Reduces Well Construction Time by 15%, Ghadames Basin, Algeria
Authors: Devine Les , Ellins Martin , Scotchman Alasdair , May Norman , Connell Sean 
Published: December 2007

Abstract
Drilling through highly inter-bedded Tertiary to Devonian age formations in the Menzel Lejmat Field, Algeria presents a number of distinctive challenges. Problematic overburden consists of abrasive sands, inter-bedded evaporite/carbonate sections, inter-bedded sand/claystone formations in addition to a 30-meter band of extremely hard dolomite. Rock strengths vary greatly with sonic transit times ranging between 55 to 140 milliseconds. Recently, Burlington Resources identified a need to improve drilling efficiency through these problematic formations. They contracted a drilling optimization service (Baker Hughes OASIS) to perform a detailed performance study of offset wells in order to plan and implement a more efficient drilling program for well (MLC-2). The objective was to increase penetration rates, preserve borehole stability, reduce the number of bits and lower overall drilling costs.
After analyzing offset wells to benchmark current performance, the service team developed an optimization plan that outlined key areas for improvement. This study included depth based drilling data, wireline log data and daily drilling reports from offset wells. This information was analyzed and a report generated that included projected lithology and mechanical rock properties as well as potential drillability problems. The team recommended specific bits, BHAs and operating practices to address these problems. A summary report of each hole section was provided for use at the rig site to ensure planned goals and targets were achieved. The report outlined depths at which potential problems could occur and what operating practices should be followed to eliminate or to minimize their severity.
The drilling of MLC-2 was a significant success. The 12-1/4" hole section was drilled with one bit for the first time and hole quality was greatly improved. The well was drilled six days ahead of the AFE curve and five days ahead of the best performing offset. This represents a 15% reduction in well time saving approximately $300,000. A detailed post-well analysis was performed to document performance achieved and to carry the numerous lessons learned forward.
Additionally, subsequent wells were analyzed in a similar manner with special attention given to the 12-1/4" and 6" hole sections. Performance improvement on these wells demonstrated that a continuous improvement process allied with a Polycrystalline Diamond Compact (PDC) development initiative, ensured bit design was optimized for rate of penetration (ROP) and length of run. The authors will document penetration rate and run length records achieved using this process. This paper will also describe process improvements and how lessons learned were fed back into the continuous improvement process to build momentum.
Drilling HT/HP Wells Using a Cesium Formate Based Drilling Fluid
Authors: Saasen Arild , Jordal Ole Henrik , Burkhead David , Berg Per Cato , Løklingholm Geir , Pedersen Erik Sandtorv , Turner Jim , Harris Michael J. 
Published: December 2007

Abstract
During the drilling and completion of the Huldra field in the North Sea, high temperature and high pressure conditions were expected and encountered in the reservoir section. The difference between the pore pressure and the fracturing pressure is small. Cesium formate had been evaluated as a potential drilling and completion fluid, but technical hurdles could not be completely addressed in time for the first well. As a result of well control problems occurring in the first well, with barite sag in the oil based drilling fluid as a contributing factor, it was necessary to use a drilling fluid with insignificant potential for sag. For the first time worldwide the cesium formate brine was chosen as a drilling fluid. This fluid could be delivered solids free with densities up to 2.2 s.g. The required down hole density in the well was 1.91 s.g. At the same time it was necessary to have as little contribution to the equivalent circulating density (ECD) from the flow as possible.
The paper describes how the cesium formate brine was used successfully as a drilling and completion fluid. The effect of the fluid on well control, hole cleaning, rate of penetration (ROP), torque/friction, ECD, formation damage, casing wear and hole stability are covered. The paper also describes actions required to minimize losses of this very expensive fluid. The challenges acquiring adequate formations logs while drilling are also described. Finally, the use of cesium formate brine during the completing of the wells with open hole sand screens is outlined.
Analysis of the Fatigue Resistance of Rotary Shouldered Connections
Authors: Collins Tony , Vaghi Francesco 
Published: December 2007

Abstract
It is widely accepted that understanding of the stresses, and thus fatigue resistance, of rotary shouldered connections requires numerical stress analysis, and that the contact between box and pin threads makes this a complex problem. Previous analyseshave usually dealt with one particular connection, and have varied in their approach to the spiral nature of the thread.
This paper covers a range of connections from NC38 to 75/8 H90, and uses multiple cases at different rotations to allow an axisymmetric model to simulate a spiral thread. The effects of alternating stress and make-up are separated, and then combined using a Gerber plot to predict relative fatigue resistance of various connection geometries. These results are consistent across connection styles, which makes it unlikely that they are due to modeling anomalies.
Conclusions are drawn as to the beneficial effects of stress relief grooves, and on the significance of the geometry of the standard groove. The results can be used with simple beam-theory analysis to make useful strength predictions, and allow the evaluation of the effects of modifications to standard connections to meet the needs of drilling and measurement tools.
New Buckling Solutions for Extended Reach Wells
Authors: Mitchell R. F. 
Published: December 2007

Abstract
New exact buckling solutions have been found for horizontal wells. These solutions include critical axial buckling force, a variable pitch depending on pipe lateral weight, length change due to buckling, pipe wellbore contact force, and pipe bending moment. Previously, these results could only be obtained with non-linear computer solutions. Applications of these results include estimating lock-up conditions, determining loads that could cause permanent corkscrewing, and determining seal lengths for horizontal well completions. Several sample calculations are presented which illustrate the use of these new results to solve practical engineering problems.
Coiled Tubing Risers: Are They Stiff Enough?
Authors: Crabtree A. , Meadowcroft W. 
Published: December 2007

Abstract
The trend over the last few years in Coiled Tubing (CT) usage has been towards a greater preponderance of large diameter, heavier wall section and higher yield strength tubing being employed. These larger, stronger section tubing strings require larger forces to be applied than those previously experienced in the industry, in order to reel and unreel the pipe from the working reel or spooler. These forces are transmitted to the riser on which the CT injector and guide arch are mounted. In turn, the toolstrings which are now more commonly used in well intervention operations are longer, requiring longer risers to accommodate them. This causes higher loads to be imposed upon the wellhead on which the riser is mounted. The wellhead, or Christmas Tree, is the primary well containment on which other well control equipment, such as Blow Out Preventers (BOP), are attached. Does this change in operating parameters now mean that the Christmas Tree is being overloaded to the point of a potential breach in its integrity?
The advent of longer risers, which are subjected to greater loads from more powerful high pull capacity injectors and more powerful reels, gives concern as to whether or not the types of riser commonly assembled in the field are stable or liable to suffer catastrophic buckling collapse. This is not readily apparent, as the types of risers being used are composed of diverse structural elements; multiple BOP’s, API flanged spools, Pin & Collar quick union riser sections, flow tees, et cetera.
This paper will present a summary of an engineering study that was undertaken to explore these questions. The study examined the effect on stability imposed by riser internal pressure, riser configuration, pipe loads and support tie-downs, as well as the loads that are being transmitted to the Christmas Tree. The study was undertaken using both existing engineering principles and Finite Element Analysis (FEA). The result of the study was the development a formulaic model, to be used within a computer simulation program, that would account for these varied inputs.
Well Intervention Outside of Short String Experiences in Java Sea - Indonesia
Authors: Hendra Yasri S. , Wibowo Wahju , Yoliandri Susilo , Rich David 
Published: December 2007

Abstract
Performing coiled tubing and wireline well interventions outside of the short string in dual completions has become an acceptable part of well intervention activities in the Offshore West Java field over the last 2 years. Previously, most well intervention activities below the end of the short string tubing were avoided due to the perceived high risk of problems such as getting stuck by wrapping tools around the long string or wedged between the long string and the casing wall.
West Java is a mature field with almost all the wells penetrating multi-layer reservoirs. Reservoir management issues have resulted in a large number of dual completions. In order for wells to maintain production at their potential rates and for the shut-in wells to be reactivated, well intervention activities need to be performed regularly in both strings. To date, 14 coiled tubing interventions outside of short string have been completed. Coiled tubing intervention consists of 8 fill clean outs, 2 cementing jobs, 1 fishing job, 1 polymer water shut-off and 2 stimulation jobs. Perforation jobs were done after performing coiled tubing cementing and water shut off jobs. All these jobs have been done with a high degree of success under a varity of well conditions (high angle, etc).
This paper will explain several problems that were encountered while working outside of short string, especially during coiled tubing interventions. Several ideas have been applied and lessons learned to overcome these problems. If we look back at the results in the Offshore West Java field over the last two years, working outside of short string has become a common practice in sustaining or even increasing production and in re-activating shut in wells.
Operational Issues Related to 120Ksi YS Tubing
Authors: Andersen J. N. , Rosine R. S. , Martin John , Deshotels Steve 
Published: December 2007

Abstract
As the coiled-tubing industry develops and begins to use higher-grade tubing materials, several special considerations must be addressed for safer operations. Tubing material properties have reached 120Ksi yield strength (YS). This paper will address some special considerations for safely operating with higher-grade material, including proveup of the tubing material, surface equipment issues, and BOP considerations. Several tests concerning these issues have been conducted to verify proper operating conditions and equipment.
A Comparison of Mud Pulse and E-Line Telemetry in Alaska CTD Operations
Authors: Ohlinger James J. , Gantt Lamar L. , McCarty Thomas M. 
Published: December 2007

Abstract
Coiled Tubing Drilling (CTD) has been used on the North Slope of Alaska to drill in excess of 250 re-entry sidetrack wells since 1994. Most of the through tubing coil sidetracks were drilled with a conventional bottom hole assembly (BHA) consisting of a mud pulse MWD tool, and a mechanical/hydraulic orienter. Recently fifteen CTD sidetracks were drilled in Alaska using a BHA that communicates to and from the surface via an electric line in the coil.
Both the conventional mud pulse telemetry system and electric line BHA are described in this paper. However, the primary goal of this paper is to compare the actual performance of the electric line BHA to the conventional mud pulse tools. In addition to drilling rate, several other drilling parameters will be discussed. Time spent surveying, logging, drilling time, orienting, and BHA handling will be addressed. (Fig. 1)
Case Study: Using CT-Deployed Scale Removal to Enhance Production in Duri Steam Flood, Indonesia
Authors: Ali Syed A. , Irfan Muhamad , Rinaldi Dedi , Malik Badar Zia , Tong Ku Ka , Ferdiansyah Eric 
Published: December 2007

Abstract
Wells in the Duri field often have a heavy scale buildup across the gravel-pack screens and the surface production equipment. This scale, which builds from calcium carbonate (CaCO3) and organic deposits in the wellbore, causes significant production decline and premature screen failures. After conventional attempts to place acid and remove scale were unsuccessful, PT Caltex Pacific Indonesia, the Company, and Schlumberger collaborated to develop a coiled tubing conveyed scale removal and fluids placement technique for gravel-pack screen completions. This paper highlights the scaling history and causes, and the yard testing, candidate recognition process, and field execution of the new technique. Post-treatment results are presented from 39 wells, showing a field production increase of more than 90 percent. The development process included scale-removal tests using numerous CT-conveyed tools. A rotating jetting tool that is optimized by software-aided hydraulics provided the maximum cleaning efficiency. Because the jetting action cleaned the screens physically, the new tool required smaller amounts of reactive fluids (xylene and acid). Safety features included a closed-loop design of the entire test circuit to avoid fluid spillage and enable safer handling and disposal of corrosive fluids.
The scale removal service, which cleans using a combination of chemical and mechanical energy, has been used in 111 wells in the Duri Steam Flood (DSF). Treatment costs are lower because less reactive fluid is needed. The inert 2% potassium chloride (KCl) brine achieves most of the cleaning action, which also optimizes the spent fluid disposal. The design of the treatment fluid also reduces the downtime required for wells to return flow to normal production. The bottom line is production gain in less time.