bluuebunny/crossref_metadata_2025_split huggingface dataset:
Automatic Mud Mixing
Authors: Nafikov R. R. , Glomstad M. S. 
Published: March 2013

Abstract
The current paper represents an overview of the automation model for drilling fluid mixing and is based on thesis works of (Nafikov 2011) and (Glomstad 2012).
The first part of investigation is based on a model developed with the help of MATLAB® and SIMULINK® softwares. The simplified mud circulation model consists of downhole and mud mixing systems. The well is divided into control volumes to imitate the moving of drilling fluid inside the drillstring and the annulus and to include disturbances such as production of cuttings and mud losses to the formation. The possibility of monitoring the downhole pressure is included as well. Mud mixing system is represented in a way of addition of chemicals for mud treatment, i.e. viscosifier (bentonite), densifier (barite) and the mud dilution property with the help of water addition. The addition of all chemicals is controlled by PID controllers. Mud mixing and downhole systems interact between each other during simulations. When fluctuations in a form of cuttings or mud losses occur in the dowhole system, the mud mixing system adapts all PID controllers to keep the desired mud properties. The performance of the model is shown in the case of closed-loop simulations. Obtained results show the expected behavior of all variables and the possibility of automatic control.
The second part of investigation will look at two principles for control of the mud mixing: cascade control and model predictive control. Compared to conventional PID-controllers with a single feedback loop, the cascade structure can utilize measurements both in the mixing tank and where the mud flows out of the well together. Continuous measuring of the mud properties is assumed. Also a controller based on model predictive control has been designed and tuned by using SEPTIC, an MPC tool developed by Statoil. The MPC controller calculates optimal inputs by minimizing a cost function subject to process constraints, defined priority levels and deviation penalties. Calculations are based on density and viscosity models found by looking at open-loop simulations of system responses to a change in different input variables. Closed loop simulations have been performed using both MPC and cascade controllers. A model for the well, "WeMod", is provided by IRIS and simulates the behavior of an actual well so it is seen how downhole conditions influence the density of the mud.
Instrumented Internal Blowout Preventer Improves Measurements for Drilling and Equipment Optimization
Authors: Wylie Robert , Standefer Jim , Anderson Jason , Soukup Ian 
Published: March 2013

Abstract
An optimized drilling system is only as efficient as the quality and accuracy of its supporting instrumentation. An increase in drilling performance, efficiency, reliability, and safety follow each new generation of measurement technology, all of which are invaluable to drilling operators and the industry.
A new system, the Instrumented Internal Blowout Preventer (IIBOP), is designed to provide accurate drilling parameters directly from the drillstring. Like other instrumentation, the goal is to allow for better decision making with regards to well construction, and to provide early warning signs of system failure or well control situations. However, other instruments are not effectively positioned to measure the load with the high degree of accuracy demanded by today's drilling operations. Reducing this error by measuring the load directly at the drillstring provides a measurement that is highly refined for today's modern control systems.
The IIBOP makes direct-load measurements along the drillstring just below the main shaft of the top drive, thereby circumventing the errors of the traditional measurements. The sensor package enables real-time streaming of data, within milliseconds, at sample rates up to 500 Hz, providing a timely series of direct measurements needed to characterize drillstring phenomena required for drilling and equipment optimization purposes.
In the IIBOP field testing, real-time string weight measurements exhibited 65% signal noise reductions compared to deadline anchor load cells, allowing for better representation of string dynamics previously undetectable. Noise was reduced in the IIBOP pressure measurements even further, by 90% when compared to the rig-supplied standpipe pressure transducers, permitting higher fidelity data for dynamic pressure event analysis. IIBOP-measured rotational velocities were also subject to less noise, while capturing both speed and direction, typically not provided by the top drive. Along with conventional measurements, the IIBOP provided entirely new parameters—bending moment and main shaft acceleration—both of which have great potential to correlate data with downhole instruments or to schedule preventative maintenance. This paper discusses the IIBOP capabilities, each parameter it measures, and test performance data compared to traditional sensors.
Drillstring Analysis with a Discrete Torque-Drag Model
Authors: Mitchell Robert F. , Bjørset Arve , Grindhaug Gaute 
Published: March 2013

Abstract
The only standard drillstring model in use today is the torque-drag model because of its simplicity and general availability. Field experience indicates that this model generally gives good results but sometimes performs poorly. For example, some friction loads predicted for casing running in horizontal wells have not been consistent with field data.
In the standard torque-drag model, the drillstring shape is taken as the wellbore shape. However, given that the most common method for determining the wellbore shape is the minimum curvature method, this assumed wellbore shape forces the bending moment to be discontinuous at survey points. This defect is dealt with by neglecting the bending moment.
A different approach assumes that the drillstring position corresponds with the minimum curvature wellbore only at discrete points. The obvious choice for these discrete points is at the positions of the tool joints in the drillstring. While these tool joints are fixed in position, they are allowed to rotate within the wellbore. These extra degrees of freedom allow solution of the bending moment problem, for continuity of bending moment can now be assured at each tool joint. Further, experimental studies of actual drillstrings have shown the potential to develop contact forces for lateral buckling that are significantly larger than predicted by smooth-pipe models. Thus, by the discrete-point assumption, we resolve two problems: bending moment continuity and underprediction of lock-up.
This paper gives a complete description of the drillstring calculation. Typical torque-drag problems are studied to compare the two torque-drag formulations. These studies give comparisons in drag forces and torques for the two models, and for the new formulation, the magnitude of the bending moments.
Analysis of Torsional Shock During Drilling
Authors: Collins Tony 
Published: March 2013

Abstract
Recent developments in drilling techniques such as Rotary Steerable tools, aggressive diamond drill bits, and dual-diameter drilling tools have greatly improved the speed of drilling wells, and have allowed efficient drilling in very difficult environments. These have created a new set of conditions that the bottom hole assembly (BHA) must withstand: a combination of high rotary speed and high, unsteady reactive torque, which have given new importance to an understanding of drillstring dynamics.
Dynamic loading of drill strings has previously been studied using application-specific models and numerical methods. This paper demonstrates the application of some simple methods borrowed from acoustics which allow approximate but very general solutions to the dynamic effects of torsional shock loading.
The results are illustrated with a case study from a well where unexpected geological features led to very high torsional shock, which caused severe equipment damage, indicating dynamic loading well beyond the accepted design parameters.
The new methodology can account for this loading as well as providing the design tools to withstand it.
The same methodology can be extended to the forces on stabilizers from transverse impacts and on bit and motor bearings from hard landings, and these are largely independent of formation properties.
Sakhalin Gas Shut-off Workovers: A Case History of Zonal Isolation at Record Depths
Authors: Molloy Richard 
Published: March 2013

Abstract
Exxon Neftegas Ltd., as operator for the Sakhalin-1 project, recently completed gas shut-off workovers on two extended reach, horizontal wells at the Chayvo Field, Sakhalin Island, Russia. The targeted oil producers were initially completed in open hole with predrill liners, standalone screens, inflow control devices, and swell packers across multiple zones at depths in excess of 9,000 m measured depth (MD). During production life, increased gas oil ratios (GORs) were observed, requiring the wells to periodically shut-in to manage gas-handling capacity at the Chayvo Onshore Production Facility. Production logs were used to identify the location of the high gas producing intervals, and a workover campaign was initiated in 2011. Relying on the learnings from similar successful workovers conducted on shallower MD wells in the field, a plan was developed to install straddle liners with swell packers inside the existing lower completion to effectively shut off the gas producing zones. The extension of previously proven practices to significantly greater depths introduced numerous technical challenges, including precise placement of small tubular straddles and mitigation of drag risk while conveying these tubulars through tight clearances. Additionally, these challenges had to be overcome while operating with new service companies and startup of a cold-stacked rig. Through a combination of planning, design, and flawless execution by a multi-functional team, the workovers were completed successfully, and post-workover production results showed significant reduction in well GORs. This paper will recap the results of this successful gas shut-off workover campaign, and the learnings obtained from straddle liner installations at world record depths.
Offshore West Africa Deepwater ERD: Drilling Optimization Case History
Authors: Jerez Hernando , Dias Rafael , Tilley Jim 
Published: March 2013

Abstract
Extended reach step-out wells provide challenging opportunities for the drilling team. A deepwater extended reach well for a major operator in West Africa required a tangent section in a soft formation maintaining an 85° drift angle for ~3,400 m (11,150 ft) in a single interval. The production section required steering the well into the best section of the pay-zone. To accomplish the drilling objectives, an exhaustive, detailed plan with multiple scenarios was required before the well was drilled.
The detailed drilling plan included the use of a tailored bottom-hole assembly (BHA) with a point-the-bit rotary steerable system and an extended gauge bit. The BHA had to overcome the natural tendency of the formation to drop inclination while creating a high quality wellbore to provide sufficient hole cleaning capacity in the deeper sections. The use of a state-of-the-art modeling tool enabled the team to balance the dynamic BHA forces while drilling to avoid common drilling problems.
The five sections required for the deepwater extended reach well were drilled with only six BHAs. The challenging 12 ¼-in. tangent interval was drilled in one run with the modeled BHA, reaching a total length of ~3,400 m (11,150 ft). This paper highlights the accuracy of the BHA modeling performance in the planning stage as this process was key to delivery of the actual results. The approach used to overcome the challenges enabled the drilling team to drill the longest 12 ¼-in section in an extended reach well in the area. This approach follows the service companies' model-measure-optimize process, which is being used to improve drilling efficiency.
Analytical Model to Characterize ‘Smear Effect’ Observed while Drilling with Casing
Authors: Kumar Aniket , Samuel Robello 
Published: March 2013

Abstract
The ‘Smear Effect’ observed during a casing-while-drilling operation helps reduce lost circulation, provides wellbore strengthening, and improves the fracture gradient so we can drill more effectively through depleted reservoirs. Several case studies have been reported confirming the formation of a smear zone around the wellbore wall, due to the plastering of cuttings and added lost circulation materials. However, even after successful application in a number of cases, a thorough understanding of the parameters affecting the formation of the smear zone and the subsequent increase in the fracture gradient is not available.
This study analyses the theory behind the phenomenon of the smear effect mechanism using case studies and existing literature, and then applies analytical models to estimate the improvement in the fracture gradient based on the drilling parameters and reservoir properties. The formation of the smear zone has been investigated by modelling the mechanism of initiating micro-fractures around the wellbore wall due to high ECDs occurring during casing while drilling. The effect of plugging these generated micro-fractures by drilled cuttings and lost circulation material has then been modelled to estimate the resultant improvement in fracture gradients expected along the wellbore open hole section. In addition, the appropriate particle size distribution required to successfully plug the micro-fractures has also been presented.
These analytical models have then been applied to a simulated field case study and the results have been analysed in the context of recorded field observations to simulate the smear effect using the proposed models. The contribution of the casing size and length, formation properties, and operating parameters on the initiation of micro-fractures and the increase in fracture gradient has also been presented to better demonstrate the mechanism of the formation of the smear zone. This study can be suitably applied to enhance our understanding of the smear effect and to use it better to our advantage.
Case History of a Challenging Thin Oil Column Extended Reach Drilling (ERD) Development at Sakhalin
Authors: Gupta Vishwas P. , Sanford Shea R. , Mathis Randall S. , DiPippo Erin K. , Egan Michael J. 
Published: March 2013

Abstract
ExxonMobil, as operator for the Sakhalin-1 project, recently planned a drilling campaign at the Chayvo Field, Sakhalin Island, Russia. The focus of this campaign is the development of a thin oil column reservoir using extended reach drilling (ERD). This paper will provide an overview of the planning of these challenging wells at the edge of the ERD envelope, the associated technical and operational challenges, and the additional complexity of targeting a thin oil column in an ERD environment. Significant well design parameters, tools, and techniques to enable these challenging wells will be presented. Results to date from this drilling campaign will also be presented.
ERD has become a commonly used technique to economically access reserves from existing infrastructure and to reduce the facilities environmental footprint. The case history described in this paper illustrates the combination of planning, technical design, and operational practices required to push the ERD envelope further.
The distance of the reservoir from shore resulted in planned well lengths at the edge of the ERD envelope. Planning of these record wells involved building upon the Operator's previous experience as well as additional tools and methods to address the unique challenges. The technical challenges included uncertainties in the location of the oil column and fluid contacts, very accurate well placement for effective reservoir drainage and preventing early gas/water breakthrough, completing long horizontal intervals, and high torque and drag. The geologic uncertainties and wellbore positioning challenges were addressed using a combination of a single near horizontal pilot hole to locate both fluid contacts and a novel technique to minimize vertical position uncertainty using formation pressure measurements while drilling. Extensive torque and drag and wellbore stability modeling were performed to design the wells, operational parameters, and equipment. Completion designs were optimized to ensure successful placement in long horizontal intervals.
Dual Fuel progress in reliability and performance for the Oil and Gas market
Authors: HENIN Eric 
Published: March 2013

Abstract
A diesel engine fitted with an aftermarket add-on gas fuel system that provides a supplemental fuel source is generally called a Dual-Fuel system. Dual-Fuel usage can lower fuel costs by as much as 70 percent, as compared to a standard diesel engine. While functional, these systems can create challenges for emissions and engine longevity.
In 2013, a leading engine manufacturer will be offering Dynamic Gas Blendings, a comprehensive Dual-Fuel solution for land drilling and land production gensets, as well as well fracturing application engines.
With average crude oil prices almost doubling from 2009 to 2012, oil and gas producers using traditional diesel powered drilling rigs have seen rising operating costs. Additionally, further government regulations on emissions and wellhead gas flaring are putting increased pressure on oil and gas producers to prioritize sustainability initiatives. In some cases, these regulations mandate the use of associated gas produced with crude oil production, much of which is currently flared today.
Oil and gas producers who use the Dynamic Gas Blending solution, as compared with standard Dual-Fuel, will benefit from:
▪ Reduced flaring. ▪ Unique safety features. ▪ Diesel and gas engine controls interconnected for automatically optimized performance. ▪ Simplified operations, with no re-adjustment necessary. ▪ Simplified operations, with no re-adjustment necessary. ▪ Improved emissions, with possibilities of certification for the genset. ▪ Extended run times from existing diesel tanks. ▪ Greater fuel flexibility, with a good tolerance of associated (flare) gases. ▪ Generator sets and gas blending systems manufactured specifically for harsh oil and gas environments.
Dual-Fuel and Dynamic Gas Blending are technologies that allow oil and gas producers to manage operating costs while being environmentally responsible. Because gas is a significantly lower-cost fuel compared to diesel and is clean-burning, they allow oil and gas producers to save money and reduce their environmental impact.
Successful Application of Concentric Casing Nitrogen Injection to Overcome Drilling Challenges and Deliver a Record Horizontal Well in the Tecominoacan Field
Authors: Rodriguez Reginaldo , Franco Roberto , Gamez Gustavo , Blas Bernardo , Gonzalez Fernando Daniel , Vasquez Jose Luis , Alcudia Hugo 
Published: March 2013

Abstract
The Jujo-Tecominoacan field belongs to the Bellota Integral Active in the Pemex South Region. It is located in the state of Tabasco, northwest of the city of Villahermosa. This field is geologically located in the Chiapas-Tabasco Mesozoic Basin and is developed to maximize production of fractured carbonate formations from the lower Cretaceous to the Kimmeridgian Jurassic. Several drilling challenges are presented including horizontal drilling in dolomites with a high compressive strength, low pressure and high temperature reservoir requiring the use of a biphasic drilling fluid with nitrogen injection through concentric casing annular space, crossing through Cenozoic members of abnormally high pressure that require managed pressure drilling, drilling through inverse geologic faults, and proximity to a salt dome.
An interdisciplinary team was formed between the service company and operator to meet the challenges of constructing the deepest and longest concentric N2 injection horizontal well in the world with a total depth of 6611 m in a Low Pressure-High Temperature ambient. A horizontal production section was drilled to a length of 862 m and with an average inclination of 84°. The main objective was to maximize production in fractured carbonate formations from the lower Cretaceous to the Kimmeridgian Jurassic formation. Managed pressure drilling was implemented in the 6 ½" hole section while drilling through the upper Jurassic production zone, allowing establishment of commercial production and incorporation of the oil reserves in these zones.
With 260 days of operation, the Tecominoacan 705 well, is the pioneer example of a combined effort of the operator and service company with the objective accomplished, setting a worldwide standard of unprecedented execution.
The Application of Advanced Gas Extraction and Analysis System Complements Early Kick Detection & Control Capabilities of Managed Pressure Drilling system with added HSE value
Authors: Patel Bhavin , Cooper Todd , Billings Will 
Published: March 2013

Abstract
Managed Pressure Drilling (MPD) has gained industry-wide acceptance as a technology that enables drilling into the challenging zones. Narrow pore pressure - fracture pressure window, depleted reservoir zones, highly fractured reservoirs and deep-water wells are few examples of such challenges. Weatherford's MPD system has proved its effective application in drilling challenging wells. Its unique early kick and loss detection software capability helps to identify such event in very early stage, take corrective action and hence to minimize the nonproductive time. Early detection of a kick / loss event helps in minimizing the potential risk posed by the event and ensure safety during the operations.
Weatherford's advanced gas extraction and analysis system uses an innovative membrane technology and high speed gas chromatograph to improve surface gas detection and analysis in real time. This capability was utilized in conjunction with accurate flow metering capability of MPD system. Various tests were carried out to validate the advanced gas detection system's capability to detect and analyze gas in mud. During circulation of the influx, data from gas detection system helped to plan the strategy gas on the surface. The test data was validated by the data from real wells.
Feedback from the advanced gas detection system also helped to control the break out of the dissolved gas from oil based mud by varying surface back pressure through automated chokes. This is very critical to ensure that gases containing hydrocarbons are handled safely on the surface. It also provided quantitative analysis of the lighter and hence volatile hydrocarbon components. Circulation rates and surface back pressure can be used to mitigate potential hazards. Use of advanced gas extraction system in combination with MPD system added significant HSE value by making well control operations more efficient and safer.