bluuebunny/crossref_metadata_2025 huggingface dataset:
Subsea Production Enhancement—Success and Failure Over Five Years
Authors: McGennis Eamonn
Published: March 2008

Subsea well intervention has been around in the North Sea for many years as documented in papers such as Pollock (1990) but in the last five years there has been renewed interst due to a combination of high oil price and aging wells. This paper will look at the actual results achieved with production enhancement work done in subsea wells across the United Kingdom (UK) sector of the North Sea over a five year period 2002 to 2007. This time frame allows the results to be seen in the context of longer term field value. All the work included in the paper was done rig-less with a specialist subsea well intervention vessel. It covers a range of different oil producing fields operated by a number of different companies. The work done was through tubing and included zone isolation and re-perforation. No work was done in any gas fields. The paper will detail the production profiles of the wells both before and after the intervention work along with a discussion of the work done and an explanation of the factors that influenced the final result both good and bad. To facilitate an open discussion of the success and failures all data is presented anonymously. The high cost of subsea wells makes it essential to maximise the overall recovery per subsea well. This paper will detail actual results which may point the way forward.
New Equipment Designs Enable Swellable Technology in Cementless Completions
Authors: Rogers Hank , Allison Dave , Webb Earl
Published: March 2008

In the oil and gas industry, it is a common practice to install production casing through producing formations, with cement providing the primary inter-zonal isolation in the annulus. However, inadequate displacement efficiencies, fluid contamination, and loss circulation intervals sometimes limit the ability of a cementing operation to provide zonal isolation sufficient to prevent annular communication over the life of the well. Formation damage caused by cementing operations can also adversely affect life-of-the-well production capabilities, thereby adversely affecting the economics of the well.

New completion technologies using swellable elastomers can offer an alternative to cementing operations performed over producing formations. However, conventional floating equipment has limited the application of swellable elastomers in some completion operations. For example, in noncemented completions where swellable elastomers provide the only annular barrier, a mechanical seal having a service life equal to the life of the well under downhole conditions is required at the toe of the production casing.

This paper describes the benefits of swellable elastomers used to provide life-of-the-well zonal isolation. Additionally, the paper recounts a problem job in which improperly selected check valves were used and new check valves specifically designed for noncemented completions were successfully introduced.

Lastly, this paper provides details about equipment designed for a south Texas well that will incorporate SEPs, float equipment, and a combination wiper plug designed specifically for a noncemented completion to be performed in late 2007 or early 2008.
Environmentally Friendly and Economic Waterflood System for October Field at Gulf Of Suez, Egypt
Authors: Ibrahim Mamdouh M , Styler James W , Shamma Hesham L , Elsherif Mamdouh A , AboElalla Essam M
Published: March 2008

October field is one of the major fields in GOS Egypt operating at 100,000 BFPD using 185 MMSCF gas lift injection gas though 50 active producing wells and 11 injection wells with 2 water source wells. Most of the resrvoirs are waterflood. October field is located 21 miles from the west shoreline in the Gulf of Suez.

With time, the performance of the producing wells showed a significant decline in productivity which was attributed to reservoir pressure decline. So, a study was done and resulted in selecting a waterflooding technique for reservoir pressure maintenance and increase of the oil recovery factor.

The economic success of a waterflood project depends on the additional oil recovery it can achieve relative to increased cost over primary development. it must aso be operated in an environmentally friendly manner.

The water source chosen for a waterflood project is usually based on a number of different factors, such as scaling tendency, rock/fluid compatibility, and possibility of bacterial activity. It is possible that a combination of sources could eventually be used. At the location of the waterflood project there may be a number of alternative water sources such as, seawater and separated formation water. Water taken from the sea and separated water associated with produced oil generally need extensive chemical treatment and expensive facilities. Would the project still give this added cost?

The October field waterflood uses a pure water productive zone for source water, which is then injected into the reservoir by two methods:

Water is produced from Zeit formation at depth 3000 ft by ESP and injected directly into water injection wells located on several adjacent platforms, without any chemical treatment. This was possible because the two waters (formation and injection water) were found to be compatible. Dumping water from the Zeit source formation directly to the oil productive zone in the same wellbore by pressure difference, otherwise known as dump flooding.

This technique has an economic advantage over conventional injection schemes by eliminating the need for source water treatment, since the provided water was found to becompatible with flooded reservoir water, formation clays, and rock matrix. It is significantly reduces facility and flow line requirements and saves deck space offshore, and also reduces environmently impact.
Safe, Effective, and Trouble-Free Rig Start Ups—Chance or Good Planning?
Authors: Cormack Dave , Richardson Ross , Steel Tamzin , Watkiss Richard
Published: March 2008

The successful start up of a rig is key to the ongoing success of a drilling contract for both operator and contractor alike. Good performance can only be achieved through competent, highly motivated and safety conscious people. Therefore, getting the HR, HSEQ & Training elements correct at the outset cannot be left to chance and good fortune but must be the result of integrated cross functional planning amongst a number of key stakeholders.

One drilling contractor had gained experience starting several major projects across the world in recent years and had developed a methodology for the ideal rig start up using a cross functional project approach. As part of its strategic growth plans, in 2007 it was going to start-up in excess of 20 very diverse rig operations over the twelve month period. Achieving success in growth of this size, speed & variety could not be left to chance but had to be as a result of good planning.

This paper will discuss how that organisation took the lessons it learned in the past and applied them in a structured manner via its Corporate HSE plan to ensure each and every start up was Safe, Effective & Trouble free. The paper analyses the successes and failures of various start ups across the organisation and demonstrates that the more involvement HR, HSEQ & Training had in the early stages the more successful the overall start up was. This was particularly true when involvement formed part of a structured and integrated plan in conjunction with all stakeholders including clients.

Given the projected volume of new work across the industry over the coming years, along with the recognised shortages of experienced personnel available, this fully integrated approach to starting up new operations is highly significant in today's drilling industry.
Expandable and Contractable Drill Bit-A Novel Technology for Hole Enlargement
Authors: Agarwal Sharad Ashok , Agarwal Navin
Published: March 2008

Expandable and Contractable drill bit is a new concept in bits which will allow us to drill super wide boreholes with radii of our choice and at depth of our interest. It will allow us to drill increased diameter borehole, having passed through restricted casing and/or tubing diameter and can provide significant advantages. Among these is the ability to incorporate novel well construction techniques, using both solid and/or expandable tubular, as well as drilling with Casing possibilities, in which casing is run immediately behind the bit. The opportunity to incorporate these techniques can thus enhance well design to yield significant economic and well control gains. Current techniques for drilling such increased diameter holes, such as bi-centered bits and under-reamers, have limitations on their ability to expand, whilst at the same time compromising the cutting structure presented to the formation. Additional limitations include limited reaming and back-reaming capabilities, as well as non-directional response. One embodiment of the technique of Drilling with Casing requires a bit which can be retrieved through existing casing string. To achieve this and to maximize drilling performance requires a device with a formation cutting structure, indistinguishable from a standard PDC drill bit but capable of being withdrawn through a restriction significantly smaller than the borehole size just being drilled. This concept leads to the possibility that a viable solution to the task of drilling increased diameter holes could be a bit that offers substantial expansion and contraction while still presenting full cutting structure to the formation.

In this paper the authors will discuss the earlier problems and solutions and present a new approach with an "Expandable and Contractable Drill Bit". They will discuss the design concept of bit, working, advantages, challenges and finally will conclude that the use of an "Expandable and Contractable Drill Bit" will be a viable tool for variety of drilling applications.
Auto Release Drill Collars
Authors: Agarwal Sharad , Agarwal Navin
Published: March 2008

The drilling industry is currently exploring various ways of reducing costs through multitude of initiatives. One of the major areas where there is potential for cost reduction is downtime due to drill string failures. Differentially stuck pipe (DSP) occurrences are common everywhere, and account for a significant amount of non-productive time and ends up as one of the major causes of increased well costs. In some areas, events related to differentially stuck pipe can be responsible for as much as 40% of the total well cost. The risks if DSP increases when drilling depleted reservoirs, and, due to the low profitability of such projects, any undesired event could hurt the economics of these developments.

Even though this is an old problem, with new drilling technologies, especially related to the use of drill collars, which is one of the main component of down hole assembly which in 60% of cases gets stuck, therefore there is a need to redesign the drill collars which can be able to drill ahead even in case of depleted reservoirs without getting differential stuck. In this paper, a new solution to DSP has been proposed. In addition, field cases are presented describing what the losses due to DSP are; the best option to reduce the risks of DSP is suggested. A simple drill collar is designed in such a way that the surface area of the drill collar is not is contact with the depleted reservoir or mud cake which is built up at the side of the wall. The drill collar is designed in such a way that it does not get differential stuck, can drill ahead and easily retrieved even in depleted reservoirs or in case of thick cake built at the side of the well bore wall. This technique will eliminate many of the conventional stuck pipe problems allowing for easier and fasten drilling, thus saving rig time and ultimately economics of the entire operation at a fraction of increased cost in the new drill collar.
Tar Sands Drilling Waste Management: A Clean Solution
Authors: Nilsen C. , McCosh K. , Kapila M.
Published: March 2008

Tar sands are a combination of sand, clay, water and bitumen. In-situ techniques using steam and/or solvents are used to reduce the bitumen viscosity such that it can be recovered and refined into petroleum products. Steam-assisted gravity drainage (SAGD) is an increasingly common technique which involves drilling two horizontal wells into the tar sand deposits. Steam and hot water are injected into the upper well to reduce the viscosity of the bitumen, which will drain into the lower well where it can be pumped to the surface. The waste generated from drilling these wells is extracted from the drilling fluid by shakers and includes sand contaminated with bitumen and drilling fluid. Treatment of this waste stream is challenging and typically these sands are stored at the rig site or transported for disposal at centralized sites.

This paper presents novel technology for treatment of the tar sands drilling waste generated from SAGD and other tar sands drilling operations. The continuous treatment process is based on hot water addition, mixing and separation techniques to reduce the viscosity and specific gravity of the bitumen to separate it from the sand. Treatment of cuttings with light to heavy bitumen contamination and varying quantities of fine sand and clay particles has shown this treatment method to be a simple and effective means of producing clean sand and recovering the bitumen component. The energy used to heat the circulating water is recycled to minimize waste and maximize energy efficiency. The cleaned sand can be blended with natural soil and safely disposed in the environment. The recovered bitumen can be used as feedstock for further processing and refining.

With the total recoverable tar sand reserves in Canada and Venezuela estimated at 300 billion barrels, the market demand for this technology is potentially immense. Effective treatment of the tar sands cuttings will convert the waste into a valuable revenue stream in an environmentally responsible manner.
Torque and Drag Software Analysis for Deciding Well Construction and Remedial Action
Authors: Roychoudhuri Biplab , ramagopal Boddupalli
Published: March 2008

In assam in India sidetrack well was decided to do horizontally after side tracking in l profile and after 90horizontal section. Original well was S profile in casing above. Well was decided for construction it was observed after torque and drag analysis that s profile l profile and horizontal section creates more surface torque. Surface torque generation was more and well was not taken for horizontal well and was converted to high angle well.

In another case well was taken up for ultrashot radius and top section of casing was S profile and only vertical wells were taken for ultrashot wells .s profile and horizontal section it was measured from out put of software generates almost double the torque.

Torque generated prognosis is a indication of wells not to be taken for drilling and well configuration was changed many viable software is available. Friction and drag is dependent on many factors like mud type well angle well profile, type of assembly used. Software modeling of well provides accurate prediction of performance and feasibility of wells. Depending on software calculation new well construction can be designed and can be altered.

Above two case study outline prevented operator from doing horizontal well and ultrashot well. Similarly many output calculation can be done like failure in tension in compression and rotational in different set of drilling condition and preventive measure may be taken for unfavourable condition.

INTRODUCTION

Well design can predict in planning stage the surface torque, failing from tension, buckling from compression failing from rotational torque. A different well plan alternatively can be devised.S profile on the top of well and below L profile and to 90 landing point. Well path was generated and modeling was done using torque and drag soft ware, it was observed that static torque of horizontal well was much greater than the static torque in high angle well.

Considering well development and field development to achieve maximum production horizontal well is to be done but because of increase in risk and uncertainity and higher torque was in well planning stage was predicted. by software Well engineer can use this tool for successful drilling strategy. If the modeling insists that there is a critical problem then well engineer can alter the design acording to suitability of the well

SOLUTION - Torque and drag modeling is the solution of this problem. By input of various factors like directional plan, drill string data, cased hole data, open hole data it is possible to predict of lowering of tubulars and consequence and different drilling operation scenarios is achieved.

DRILLING SOFTWARE -Drilling software includes tubular data. Pipe OD/ID, pipe density, young modulus tensional yield, torsional yield, weight per ft tensile strength and torsional data is key input

Directional profile of the well is measured depth, inclination, azimuth.

Output calculation are done under different set of condition
Reducing Risk by Using a Unique Oil-Based Drilling Fluid for an Offshore Casing Directional Drilling Operation
Authors: James Reagan , Randeberg Øystein
Published: March 2008

The conventional drilling approach of employing a drillstring and bottomhole assembly with bit for drilling purposes and eventually running a casing string includes several tripping operations that leave the wellbore open for extended periods of time as an alternative to drilling-with-casing operations where the bottomhole assembly is attached to the casing. This eliminates additional drillstring tripping as drilling and running casing are performed simultaneously. This type of application reduces the number of string trips needed to complete a section, thus saving operational time and associated costs. As the diameter of a casing is larger than a drillstring, this method generally increases the Equivalent Circulating Density (ECD) as pressure losses increase owing to the reduction of the open hole and casing string annulus area. Casing directional drilling operations provide a much narrower drilling window with regards to restrictions in the annulus thus increasing the chances of reaching fracture pressure compared with conventional drillstring operations. To negate the resultant increase in ECD, the rheological profile of the drilling fluid must be designed appropriately.

This paper discusses a unique oil-based drilling fluid system weighted with treated micronized barite slurry (TMBS) that has more recently been developed and used successfully in the Eldfisk field of the Greater Ekofisk area, Norway. The drilling fluid system provides low viscosity and a relatively low flat rheology, reduced torque values, and superior sag stability, thus delivering a fluid of low ECD contribution, low-pressure peaks, very effective hydraulics performance and static stability. These exceptional fluid characteristics make the system an excellent solution for drilling sections where the difference between pore pressure and fracture pressure is narrow. This was particularly so in this case where the stability of the fluid from sag potential was crucial for the improved success of the drilling-with-casing operation. Any solids sag onto the latching tools or bottomhole assembly (BHA) with the casing could have caused interference.

The system had been used before for differing hole conditions including managed-pressure drilling and extended-reach wells, in high-temperature, high-pressure (HTHP) wells, and now with competence in a casing directional drilling operation.
Annular Pressure Loss Predictions for Various Stand-off Devices
Authors: Yao Dongping , Robello Samuel G.
Published: March 2008

During drilling and cementing operations, many stand-off devices, such as centralizers, stabilizers, reamers, turbulators, cutting bed impellers, and friction reduction devices are widely used. Some of these devices are designed to enhance the displacement efficiency during cementing operations, to increase hole cleaning efficiency, or to reduce torque and drag during drilling operations. The hydraulics program for the deep and especially ultra deep wells constitutes a significant portion of the well planning. Challenges associated with extreme depth and different types of downhole tools used in the drillstring translate to additional problems to the well design. Few studies have explored the pressure losses arising from these attached devices in the drillstring or casing string, and the pressure losses caused by them are assumed either negligible or ignored. The geometrical designs of these devices are relatively irregular and complicated, which is one of the major difficulties for pressure loss calculations. Non-Newtonian drilling fluids further complicate the problem. A study is necessary to determine the impacts of these devices on the pressure loss calculations and thereby the effects on downhole circulating density. These devices alter the flow stream and especially the angular bladed type cause the flow to swirl. This flow is complex, which underpins the effects of the pressure drop calculation across these devices. The paper describes a method and equations to calculate the pressure losses due to the stand-off devices.
Casing Drilling in the San Juan Basin to Eliminate Lost Returns in a Depleted Coal Formation
Authors: Robinson Shon D. , Bealessio Tom M. , Shafer Randall S.
Published: March 2008

A casing drilling pilot program was conducted in the San Juan basin to determine if lost returns could be eliminated in a depleted coal formation. The pilot program proved that casing drilling can mitigate lost returns drilling through the coal and can be made economic in a low cost environment.

The reduction in the amount of fluid lost should result in less damage to offset producing coal wells, resulting in higher ultimate recoveries. Development costs may also be reduced, by replacing directional wells drilled to avoid lost return zones, with lower cost vertical wells.

A total of six wells were drilled with non-retrievable casing drilling bits. Two wells were drilled using a casing drilling bit on drillpipe (DP). Based on the bit performance four other wells were drilled with casing. Three wells drilled through the coal and had losses that were eliminated with casing drilling. One well experienced a bit failure and did not drill into the coal.

The pilot program was completed with significant learnings. Losses were healed in the coal. A non-retrievable casing drilling system successfully drilled to the intermediate casing point without a trip. The bit design was changed significantly and resulted in 54% improvement in drill rate with instantaneous rates of penetration (ROP) similar to traditional polycrystalline diamond compact (PDC) bits.

The initial casing design was modified to decrease vibration, and eliminate fatigue after a failure was experienced. The casing drilling bit was successfully drilled out with an air hammer and hammer bit. Other tools and techniques applied during the pilot program included cement stage tools, foam cement, and aerated fluids to reduce the equivalent circulating density (ECD) and to improve ROP.
A Case History of Casing Directional Drilling in the Norwegian Sector of the North Sea
Authors: Bourassa Kevin , Husby Tove , Watts Rick , Oveson Dale , Warren Tommy , Bjoerneli Hans Magnus , Lesso Bill , Sunde Frode
Published: March 2008

In January 2007, ConocoPhillips completed what is believed to be the first well directionally drilled with casing using wireline retrievable bottom hole assemblies from an offshore installation. ConocoPhillips has considerable experience with this technology in reducing drilling days on predominately vertical land wells in South Texas. It was desired to determine if the same benefit could be realized in the offshore environment; where directional drilling is required. A candidate development well was identified in Norway on the ConocoPhillips operated Eldfisk Bravo platform that could benefit from advantages seen with Casing while Drilling. Two land based tests were conducted to confirm the ability to conduct casing directional drilling in wells similar to those expected in Norway. Simultaneously, a detailed plan for drilling the well in Norway was developed.

Two production casing strings (10 ¾-in. and 7 ¾-in.) were successfully drilled directionally through the overburden section on the Eldfisk well. The well had a complex 3-dimensional well path with inclination up to 60°. All running and retrievals of the BHAs was planned to be done with wireline and a purpose-built traction winch system rated to a working load of 40,000 lbs. Once the 7 ¾-in. production casing was cemented, the casing string was converted to a production liner with an expandable liner hanger and the upper section of 7 ¾-in. was retrieved. In all, 10,968 ft of the 13,600 ft well was directionally drilled with casing.
Development, Testing, and Field Deployment of a Hydraulically Expanded Solid Liner Hanger in a Casing Directionally Drilled Well in Norway
Authors: Bourassa Kevin , Husby Tove , Watts Rick , Hazel Paul , Nussbaum Chris , Wood Peter
Published: March 2008

When ConocoPhillips (COP) decided to conduct Casing Directional Drilling (CDD) operations from a platform in the Norwegian Sector of the North Sea, the well design required that the drilled in 7-3/4" production casing string be converted into a liner prior to completing the well. There was a challenge in identifying a liner hanger system that would be suitable for CDD operations; that did not require a running tool; would maintain a full internal diameter (ID) for running and retrieving bottom hole assemblies (BHA's) and would act as a barrier against gas migration over the service life of the well.

Expandable technology(1) was identified as a potential solution. Once a service provider was identified, a basis of design was established and testing began. The end result after eighteen (18) months of work was a successful field deployment of a 7-3/4" liner hanger that was drilled in from surface; successfully expanded into 10-3/4" casing; had a load capability of over 440,000 lbs (200 metric tons or MT) and a 5,000 psi (345 bar) gas tight seal qualified to ISO 14310:V0.

This paper will describe the development, testing and actual deployment that took place between December 2006 and January 2007.
Automated Real-Time Hookload and Torque Monitoring
Authors: Kucs Richard , Spörker Hermann F. , Thonhauser Gerhard , Zoellner Philipp
Published: March 2008

Today important parameters to enable a reduction of lost and hidden lost time during drilling, like hook loads for pulling and slacking off the drill string, and torque for drill string rotation, are still taken manually. Analysing torque trends during drilling and reaming is hardly done.

A key to reduce lost and hidden lost time by analysing drilling data is to automatically recognize ongoing operations in real time from this data. That allows the automatic identification and picking of pulling-up; slacking-off and rotating hook loads, as well as torque values without spending extra time or work force. Relevant parameters can be sampled and analysed automatically in real time from the rig sensor data stream without interfering drilling operations.

This automated process allows monitoring changing torque and drag trends for each stand of drill string moved during drilling, tripping, or reaming operations. To monitor trends in the torque and drag development in real time, parameters may be combined with simulated hook load and torque curves in a graphical way. Simulated values are imported from engineering applications. This allows the user to react immediately, not only after hand taken values are manually entered into a graph. The possibility to broadcast all the data to computers worldwide enables a great level of cooperation.

Instant measures against increasing torque and drag can be taken before reaching critical ranges on a stand per stand basis. Also excessive reaming and washing can be avoided as low torque and drag may be an indication for a good hole quality. This can save wellbore treatment time.

The paper presents the development of the system, its validation against live well data from recent 20,000ft wells in the Vienna basin and the planned application of the system on an extended reach field development project offshore New Zealand.
Installing 56 Surface Casing Strings in 40 Well Slots Successfully in Bohai Bay, China
Authors: Fu Frank , Actis Stephen C. , Strachan Kevin
Published: March 2008

ConocoPhillips is developing the Peng Lai field in Bohai Bay offshore China with six wellhead platforms (WHP) in 28 m (92 ft) of water. Phase I entailed one 24 slot WHP and a leased FPSO that has been in production since 2002. Phase II will have five 40 slot WHP's and a permanent FPSO. Phase II production began in 2007. The 24 inner slots of four of the Phase II WHP's will have 20″ drive pipe conductors and the 13 3/8″ surface casing will be installed by drilling with casing. The 16 outer slots, 8 on the north row and 8 on the south row, will have 36″ drive pipe conductors and provide dual bore 13 3/8″ surface casing strings in each slot. These holes will be directionally drilled at a slight angle to facilitate subsequent directional drilling. The 56 wells drilled from a 40 slot WHP reduces the size and cost of the platform while providing additional wells to meet the reservoir development plan.

A portion of the wells will be "pre-drilled" from a jack-up through the WHP jacket while the topsides are under construction. The 13 3/8″ surface casing strings, using both the drill with casing and dual bore methods, are installed during batch setting programs. The jack-up pre-drills wells below surface casing until the topsides installation begins, at which time the jack-up moves to the next platform and repeats the process. After the topsides are installed on the WHP, a self contained platform rig continues the drilling and completion program. The drilling program on the last WHP, to be installed in 2009, will be conducted exclusively from a platform rig, including the 13 3/8″ drill with casing program in all 40 slots.

This paper will describe the well construction program as part of the field development plan, the installation procedures, results of the surface casing installation programs and the drilling cost savings realized as a result of using drill with casing and dual bore conductor technologies.
Drillstring Solutions Improve the Torque-Drag Model
Authors: Mitchell Robert F
Published: March 2008

The only standard drillstring model in use today is the torque-drag model, and because of the simplicity and general availability of this model, it has been used extensively for planning and in the field. Field experience indicates that this model generally gives good results for many wells, but sometimes performs poorly.

In the standard torque-drag model, the drillstring shape is taken as the wellbore shape. Considering that surveys are taken within the drillstring, this is an excellent assumption. However, given that the most common method for determining the wellbore shape is the minimum curvature method, the wellbore shape is less than ideal, because the bending moment is not smooth at survey points. This defect is dealt with by neglecting bending moment, but as a result of this assumption some of the contact force will also be neglected.

If the wellbore shape is the drillstring shape, why not use analytic drillstring solutions to model the wellbore trajectory? Before these solutions can properly interpolate the survey data, they require some modification. This paper shows how this can be done in a simple and efficient way, so that little of the calculation speed of the conventional model is lost. With this new wellbore model, the simple torque-drag model becomes a full stiff-string formulation.

The paper gives a complete description of the wellbore trajectory calculation, including tests of circular, helical, and catenary trajectories to verify the accuracy of the formulation. Several example problems with different inclinations and wellbore curvatures are studied to compare the two torque-drag formulations. These studies give comparisons in execution time, drag forces, and torques for the two models, and for the new formulation, the magnitude of the bending moments.
Optimized Deepwater Cement Design for Record-Length Expandable Liner
Authors: Schultz Don , Pollard Greg , Fuller George , Langlinais Joey , Serio Michael , Bradley Jasen
Published: March 2008

During a sidetrack operation out of 9 7/8-in. casing on a deepwater well in Green Canyon Block 243, Gulf of Mexico, unexpected hole conditions were encountered that required the use of an additional casing string. The decision was made to run a 7 5/8 x 9 5/8-in. expandable liner in the 8 1/2 x 9 1/2-in. wellbore. The liner would expand to provide an inside diameter of 7.71 in., allowing space for a 7-in. production liner in the targeted interval.

The 6,867-ft liner (pre-expansion length) is currently the world record for the longest expandable liner set to date and presented several challenges for cement job design. The liner would be cemented conventionally before the expansion operation. Expansion time was calculated to be approximately 17 hours, allowing the fluid time for the primary lead cement, with a safety factor, to exceed 19 hours. The tail cement had to exhibit good compressive strength around the shoe track, and the operator specified top of cement (TOC) at 17,000 ft to protect a secondary pay zone. Slurry properties were simulated to meet fluid times required for the liner expansion. Standard API lab tests used for cement testing were modified to accommodate this lengthy operation.

The expandable liner was set at 20,605 ft measured depth (MD) and 19,930 ft true vertical depth (TVD) with a maximum hole angle of 36°. The liner was cemented successfully using an extended thickening-time lead slurry mixed at 15.7 lb/gal, followed by a 16.2-lb/gal tail slurry with a shorter pumping time to achieve good strength at the liner shoe.

After drilling out the liner, the operator obtained a 16.8-lb/gal equivalent (PPGE) formation integrity test (FIT) and resumed drilling to the target depth. The cement-evaluation log showed excellent bonding behind the expandable liner with TOC at 17,000 ft as planned. Operational details and cement design considerations are provided in the paper. Emphasis is placed on wellbore configuration, expandable installation procedures, and hole preparation, a full understanding of which is the beginning of a successful cement job.
High Speed Telemetry Drill Pipe Network Optimizes Drilling Dynamics and Wellbore Placement
Authors: Ali T. H. , Sas M. , Hood J. A. , Lemke S. R. , Srinivasan A. , McKay J. , Fereday K. S. , Mondragon C. , Townsend S. C. , Edwards S. T. , Hernandez M. , Reeves M.
Published: March 2008

This paper discusses the successes and lessons learned during the first deployment of a High Speed Telemetry Drill Pipe Network with a Rotary Closed Loop System (RCLS) and Triple Combo suite in North America. The paper details the operational experience while drilling a lateral well with an emphasis on drilling optimization and LWD processing; given the ability to receive real-time, memory quality, data via a telemetry drill pipe network.

Recent advances in Logging While Drilling technologies call for broader bandwidths and faster telemetry data rates for full utilization of data available downhole. In addition to the improvements in LWD technologies, there has been a remarkable development of downhole drilling dynamics and optimization tools. A telemetry drill pipe network that delivers real-time memory quality data at 57,000 bps transmission rates, provides a step change in capability for the industry – dramatically changing the decisions that can be made in real-time

The major lessons learned during the project were i. Real-time monitoring is a valuable tool for controlling and mitigating dynamic dysfunctions downhole resulting in immediate ROP improvements; ii. High volume of real-time memory data imposes new challenges on surface software systems; iii. High resolution bore hole images via telemetry drill pipe facilitate real-time on-site dip picking and analysis of downhole conditions; iv. Handling of telemetry drill pipe at surface plays a key role in improving the efficiency of overall drilling operation.

With a telemetry drill pipe network, the present generation of drilling engineers can have high quality down-hole dynamics information and mechanical specific energy (MSE) data real-time while drilling. Likewise, the geologists and petrophysicists can have access to 8 sector gamma images and 16 sector density images, real-time via telemetry drill pipe. The success of the project has provided the industry with an impetus to pursue this technology as a ground-breaking path towards making real-time informed decisions while drilling.
Novel Automation Interface Improves Drilling Efficiency and Reliability
Authors: Florence F. , Guggari M. , Koederitz W. L. , Rodriguez H. , O'Kelly C. , Russell D.
Published: March 2008

Automation of drilling operations to date requires substantial capital investment and major construction or renovation to implement the technology. A new method has been developed using a small electronic controller coupled to the existing control system of conventional rigs, land and offshore. This simple, reliable controller is a conduit for service companies and operators to apply the latest algorithms to drilling operations employing mechanical or electrical rigs of many different designs. This will inevitably lead to experts directly controlling drilling operations which will mitigate the shortage of experienced personnel forecasted for the next decade.

Such a system is commercially available as a mud pump controller. To date, it has been used on a variety of land installations and on a deepwater drillship in the Gulf of Mexico. Complex command sequences for downhole tools are easily implemented from pull-down menus. Downlinking to rotary steerable tools continues with virtually no mis-runs and often at depths, speeds and differential pressures/flow rates unattainable when done manually. It was also successfully field tested with rotary tables and drawworks brakes. In this application, it was also used to limit the driller's speed settings to prevent inexperienced personnel from inadvertently damaging the wellbore or surface equipment.

This paper examines laboratory data, field tests and results from initial commercial applications to quantify risk reduction available from the new system. Offshore operations have seen 24 hour time reduction per hole section with the potential to increase this another 72 hours per well. Land operations should see proportional savings.

This new drilling automation system will radically change the way wells are drilled in the future. It will be the delivery mechanism to implement complex commands to streamline and safeguard drilling operations for existing drilling rigs. The industry can focus on algorithms to apply new drilling techniques to reduce drillstring vibrations and fatigue and, more importantly, to minimize wellbore stresses and the expensive trouble time that results.
Application of Connection Productline Evaluation
Authors: Powers James P. , Baker David A. , Chelf Michael S.
Published: March 2008

Premium threaded casing and tubing connections are expected to maintain structural integrity and sealability performance throughout the life of the well. Industry and various company standards for evaluating connection performance via physical testing on specific size/weight/grade combinations have been optimized. The industry now seeks methods to infer performance for combinations that have not been tested, based on completed tests. Time and cost savings are realized by extending test results within a family compared with multiple individual evaluation programs.

One operator has implemented an approach to evaluating a family of premium connection designs across a range of size/weight/grade combinations. This approach includes a comprehensive review of the threading specifications within the family to provide a consistent design approach, finite element analysis of all of the family members within the range under extreme tolerance and load conditions to evaluate the consistency of performance, and rigorous physical testing of combinations representing the boundaries of the range or worst cases within the range.

The operator has confidently assigned performance envelopes for several premium connection design families. Physical testing and finite element analysis evaluations assessed design and performance consistency, and established specific design-family-specific performance criteria. This paper will describe the process implemented to provide appropriate performance assessment of a connection product family for which all size/weight/grade combinations were not tested.
A Systematic Approach to a Better Understanding of the Concentric Hole-Opening Process Utilizing Drilling Mechanics and Drilling Dynamics Measurements Recorded Above and Below the Reamer
Authors: Thomson Ian , Radford Steven , Powers Jim , Shale Les , Jenkins Mark
Published: March 2008

Well known in the oil and gas industry is the importance of understanding drilling system vibrations and bit-reamer weight transfer when drilling with hole openers.

A field testing program was carried out on a full-scale experimental test rig in the state of Oklahoma, USA, with known lithological formations, in order to evaluate underreaming system designs. In this context, the underreaming system comprised the bit, the drive system, and the underreaming element.

To fully understand how the system interacts with the formation and reacts to inputs from the surface, drilling mechanics measurements were taken above and below the reamer element. Drilling dynamics measurements were also taken at three places in the BHA, with two drilling dynamics packages spaced out below the reamer and one positioned directly above it. That way, dynamics on the bit and reamer could be studied separately to understand how bit and reamer performance affect each other and the overall system dynamics.

The first well was directionally drilled with a rotary steerable system, concentric reamer, and vibration monitoring equipment set up in an industry-standard arrangement. This paper will describe how the findings and learning from the initial field test led to bit redesign and operational techniques implemented to enhance the drilling system stability. Another borehole was then drilled through identical formations with this improved system, offering a unique detailed comparison between the two field tests. The new bit design allowed the bit to control the drilling rate with better weight distribution between bit and reamer, significantly reducing vibration, and in this study, without impacting penetration rate.

A concentric reaming tool new to the drilling industry was used in both wells as a part of this study and will also be described. This tool demonstrated good steerability with a rotary steerable tool system and operated properly, drilling closed, activating, reaming, and finally, closing for retrieval from the hole.
Drilling Vibrations Modeling and Field Validation
Authors: Bailey J. R. , Biediger E. A. O. , Gupta V. , Ertas D. , Elks W. C. , Dupriest F. E.
Published: March 2008

A modeling tool has been developed that enables drilling engineers to design vibration resistant bottom hole assemblies (BHA's), given tool placement constraints and desired directional objectives. This model can be applied to configurations with the majority of common components, including rotary steerables, bi-center bits, roller-reamers, hole openers, and eccentric mass stabilizers. Modeling results have been validated in large, intermediate, and small hole sizes. In these applications, predicted behavior and field observations have compared well. Redesign has resulted in improved drilling results, including increased on-bottom drilling time, longer tool life, higher Rate of Penetration (ROP), reduced non-productive time associated with tripping, and even better hole quality.

As use of the operator's ROP management process has spread through the company (Dupriest, 2005), downhole vibrations have been identified as one of the most significant factors limiting further ROP and footage improvements. Rig site personnel use vibrations data from downhole sensors and Mechanical Specific Energy (MSE) diagnostics to achieve the minimum vibrational levels possible with the existing assembly. The nature of the remaining vibrations is identified, and the BHA is then redesigned in a way that addresses the specific form of vibration that is limiting performance. The field assessment of the vibrational limiter and the redesign process are repeated from well to well.

Vibrations mitigation is posed more as a design problem than an analytical one. The model characterizes the lateral vibration, or whirl, tendencies of BHA's, enabling quick and easy comparison of potential BHA design candidates. A BHA can be designed to minimize vibrational tendencies for a given set of operating parameters, or the optimal operating parameters can be predicted for a given BHA configuration. The model has unique displays to support both pre-drill vibrations forecasting and post-drill hind casting. Several case studies are provided to illustrate the value of this technology.
Present and Future Well Intervention on Subsea Wells
Authors: Jøssang Siri Nordbø , Friedberg Robert , Buset Per , Gramstad Bernt
Published: March 2008

World wide there are more than 3000 subsea wells and the number is growing. To increase the oil recovery from these wells there is a demand for an efficient subsea light well intervention service, which includes repair, scale removal, installation and manipulation of mechanical devices (valves, plugs, screens etc.), re-perforations, zone isolation, fluid sampling, PLT, chemical treatment, well abandonment etc. Traditionally, this type of work has been done by semisubmersible drilling rigs. Light Well Intervention technology makes this type of service possible from a monohull vessel. The technology reduces the intervention cost significantly, enabling more intervention work and resulting in better exploitation of subsea wells. The long term objective is to increase the oil recovery from subsea wells in the North Sea from average 45% to 55%.

An Alliance of a vessel owner, a wireline operator and a well control company offers a complete LWI (Light Well Intervention) service. The Alliance has performed LWI services on the UK- and Norwegian sector since spring 2005 and made interventions on more than 30 wells, after succeeding to land a long-term contract. Continuous operations have resulted in ongoing improvement of systems and operation, and provided important contributions to design and construction of new LWI vessels and systems.

This paper will discuss the LWI service in general, present challenges met, experiences made, and lessons learned during the 2006 and 2007 campaigns. Focus will be held on the umbilical-, deployment- and handling systems, weather limitations and scope of work. Another important issue is providing an integrated service team and to establish onboard the vessel a safe and efficient working environment. The service is continuously being improved and new technology being developed. Coil tubing service, as added well intervention functionality, will further be introduced on a light well intervention vessel in 2009, and presented in the paper.