Bourassa, Kevin Arthur (ConocoPhillips) | Husby, Tove (ConocoPhillips Co) | Watts, Rick Deuane (ConocoPhillips Co) | Oveson, Dale (TESCO Research & Development) | Warren, Tommy M. (Tesco Corporation) | Bjorneli, Hans Magnus (Schlumberger) | Lesso, William George (Schlumberger) | Sunde, Frode (Schlumberger)
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.
In three years, Hercules Offshore, Inc. went from a privately held company with five jack-up drilling rigs and 22 liftboats to a publicly held corporation with 73 drilling rigs, 64 liftboats, and a workboat fleet. This rapid growth has left the challenge of growing one HSE or safety culture from 10 different parts. Initially we counted on the talent of the teams with only a basic safety management system as a framework. Leaving people to do what they have always done fostered a protective or closed culture rather than the culture of open dialogue and reporting desired in a robust safety culture.
We intend to share the methodologies being currently used to grow one safety culture from many. Best practices are only a starting point. Often safety professionals attempt to grow a safety culture by adding to what is already in place, looking for more tools, and complicating the basic tools. This operates under the assumption that most understand the purpose and workings of the basic tools in their safety management system.
Our observation has been that not only have some of our tools turned into paper exercises, but many do not even get that they might be something more. We are now working under the assumption that the basic safety tools like Job Safety Analysis,
Permits to Work, Time-Out and Hero (our behavioral observation tool) are not obvious. They are the building blocks of a safety management system requiring understanding. Through immersion training involving everyone, we are getting back to purpose by simplifying and streamlining, and creating belief and accountability.
Over the years we have over-complicated simple concepts. Our goal is to simplify the basic safety tools, so that when people are using them, they are using them well and for the right reasons.
Mean Time Between Failure (MTBF) has been a traditional measure of equipment reliability. In the drilling industry, MTBFs of some downhole directional drilling tools are exceeding 1,000 hours, indicating downhole tools have become more reliable and suggesting that tool failures are an unlikely event.
In 2005, ExxonMobil Development Company - Drilling initiated a study on Rotary Steerable System (RSS) and Formation Evaluation (FE) tool failures. Analysis indicated that globally, every third Bottomhole Assembly (BHA) was pulled because of an equipment-related failure. These results did not match the MTBF numbers provided from the service sector.
Further analysis indicated that MTBF is a good metric for a manufacturer to classify the statistical reliability of individual components in a consistent operations environment. However, it is not a good metric for measuring reliability of an entire BHA that consists of many components. As BHAs become more complex, the MTBF of single components must increase in order to maintain existing reliability of the total system.
ExxonMobil is now tracking the RSS performance by run success. This approach favors a total system strategy where each BHA component is evaluated based on its ability to optimize the reliability of the entire BHA.
The four elements of this strategy are:
The goal of the initiative is to have the best tools used in the correct application within drilling parameters that do not exceed the tool design. With this achieved, ExxonMobil expects to see a decrease in failures and reduction in cost not only to the organization but to the service providers as well.
The Erha-7 well is a deepwater exploration well that was ultimately drilled with a dynamically-positioned rig in 1,074 m water depth within Nigeria's Offshore Mining License (OML) 133 (formerly OPL-209).
During the early well planning process, the site investigation team identified numerous, extensive shallow hazards stacked in the area surrounding the Erha-7 geologic targets. These hazards were evaluated by the drill team, site investigation team, and the business unit to optimize the well location and minimize the risk of encountering shallow gas-charged sands.
The final well location allowed vertical drilling of the riserless conductor-hole interval and required directional drilling below the conductor to intersect vertically stacked geologic targets. Because of the close proximity to numerous shallow hazards and the limited seismic resolution, the final well location was still deemed to possess a moderate risk of encountering gas-charged shallow sands.
This paper discusses the shallow hazards planning involved with the Erha-7 deepwater well. It summarizes the limited industry experience regarding deepwater shallow gas flows and the associated safety considerations. The paper presents the modeling and evaluation of shallow gas flows and dynamic kills used to quantify the potential benefits of drilling a pilot hole, and discusses the sensitivities associated with performing an effective dynamic kill. Finally, a discussion of the dynamic kill plans developed to prevent and effectively mitigate a shallow gas flow.
This paper describes a fluid system developed to build integrity continuously to prevent lost returns while drilling. The primary attributes of the fluid that enable this are high solids content and extremely high filtration rates, as reflected in API fluid loss tests. It is referred to here as a drill and stress fluid (DSF).
In field applications, DSF water-based systems appear to be effective over a wide range of conditions. Circulating pressures have been sustained that exceed integrity at the bit by 1.0 to 3.0 ppg without detectable losses in depleted formations with permeability ranging from 1 to 1,000 md and pay zones of 50 to 700 ft (165 to 2,300 m) in length. The mechanism through which the DSF is believed to arrest the growth of lost returns fractures and build near-wellbore stress is described. Generalized design criteria for a DSF system are presented and the assumed relationship between the design parameters and fluid performance is discussed.
The results of the application of DSF are presented for eight wells, including post treatment evaluation logs of the drilling-induced fractures created while building stress. Operational practices that facilitate the safe use of an extremely high fluid loss system with overbalance exceeding 2,000 psi are also discussed.
Maddox, Bradley Dean (ECA Holdings, L.P.) | Wharton, Molly (Halliburton Energy Services Group) | Hinkie, Ronald Lee (Halliburton Energy Services Group) | Balcer, Brent Powell (Halliburton Energy Services Group) | Farabee, Mark (Ely & Associates Inc.) | Ely, John W.
This case-history paper presents an account of the application of expandable (swelling) packers and a hydrajet perforating stimulation technique to perform a cementless completion and hydraulic stimulation in a 350o F, openhole horizontal well of 15,700 ft total vertical depth (TVD). Resulting production was more than three times that of an offset vertical well.
The first Wilcox Meek 2 well in the Brazos Bell Prospect Area was drilled and completed to test the effectiveness of horizontal well technology in tight-sand formations. This paper presents the cementless completion process and explores the effectiveness of horizontal-well technology in tight sands by comparing initial horizontal-well production rates to those of offset vertical wells.
The well, which was the first horizontal Wilcox in the area and probably the deepest horizontal well completion for a sandstone reservoir in South Texas, used a 5 ½-in. / 3 ½-in combination string as a production string. The 3 ½-in casing was run in the openhole horizontal lateral section and extended into the 7 5/8-in liner casing. It employed five swellable packers, strategically placed on the string to facilitate isolation for optimum stimulation results. An additional swellable packer, larger than the previous five, was run on the top of the 3 ½-in casing string and was placed inside the 7 5/8-in casing to help ensure complete isolation of the annulus. The swelling packers were activated over an 18-day period by hydrocarbons present in the oil-based mud (OBM) in the annulus.
Following packer activation, four fracture-stimulation operations were conducted in a non-cemented hole using a unique fracturing technique that incorporates hydrajet perforating with coiled tubing (CT). This technique allows for (1) multiple stimulation treatments to be performed in series without the CT being removed from the hole, (2) larger stimulation stages, and (3) maximum surface-area exposure to the fracture pressure without formation damage caused by cement.
Shell Exploration & Production Company continues to execute redevelopment slim hole sidetracks using Managed Pressure Drilling (MPD) on the Auger TLP in Deepwater Gulf of Mexico. Four sidetracks have been successfully drilled utilizing a Dynamic Annular Pressure Control (DAPC) system to eliminate lost circulation and borehole instability events.
Execution of MPD continues to improve, resulting in operational efficiency gains and allowing access to previously unattainable reservoir targets. Intervals previously considered impossible to drill due to depletion induced frac gradient reduction are being drilled and cased trouble free with MPD.
Recent MPD well designs have incorporated reduced static mud weights below pore pressure to manage the available drilling margin. Bottom hole pressure variation from the defined set point has been reduced and excursions outside of the target pressure window are being eliminated during subsequent MPD well operations.
Auger's field redevelopment history, well designs and Managed Pressure Drilling designs will be reviewed. Execution of MPD operations will be addressed in detail focusing on engineering and operational improvements throughout the four MPD sidetrack campaign.
Extensive research and development has produced a new generation of PDC bits, designed to drill harder and more abrasive formations than standard PDC bits, including those with the latest abrasion-resistant cutters.
The new-generation PDC bits allow drilling of formations that once were only drillable with TCI roller-cone bits and impregnated diamond bits. The success demonstrated in Algerian applications is likely to spread throughout the world, raising the performance bar and expectations for PDC bits.
The first new-generation PDC bits were introduced in a 12 1/4-in. Jurassic-Cretaceous application in the Algerian Sahara desert and immediately set performance records in one of the area's difficult fields. This application is characterized by a 2000-m long vertical section usually drilled with packed rotary BHAs through a variety of formations ranging from soft and abrasive to very hard. The challenge in this area for PDC bits is drilling the whole section in one run and maximizing the ROP. This challenge is made more difficult by a series of interbedded hard/soft formations that generate extensive vibrations. There also are extensive abrasive layers, leading to premature cutter wear and loss of aggressiveness and ROP.
In this paper, the authors will describe the technologies that were developed and included in these new PDC bits, as well as the field results in a specific application in the Algerian Sahara desert. The authors also will illustrate the importance of applying the correct operating practices in the achievement of record ROPs.
Bourassa, Kevin Arthur (ConocoPhillips) | Husby, Tove (ConocoPhillips Co) | Watts, Rick Deuane (ConocoPhillips Co) | Hazel, Paul Roderic (Read Well Services Ltd.) | Nussbaum, Chris (Read Well Services Ltd.) | Wood, Peter (Read Well Services Ltd.)
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.
A new method of completing multiple-layer formations has been successfully tested in the United States and Canada. This
new method places sliding sleeve valves in the casing string and completes the well with normal cementing operations. The
sliding sleeve valves are opened one at a time to fracture layers independently without perforating.
Completions using these casing valves are called Treat And Produce (TAP) Completions and have a unique design feature in
the valves that allows a theoretically unlimited number of valves to be placed in a single well without incremental reductions
to the internal diameter (ID). This near full bore feature allows normal cementing operations to be preformed with a special
cement wiper plug. A control line is connected between sequential valves. When the bottom valve opens, the control line
becomes pressurized and transfers the bore pressure to a piston in the valve immediately above. This piston squeezes a Cring
and makes the ID smaller. At the end of the fracture treatment to the lower valve, a dart is dropped during the flushing
operation. This dart lands on the squeezed C-ring and seals the bore inside the sliding sleeve. Pressure is then increased until
the next valve is pumped open. When this valve opens, the next control line is pressurized, squeezing the next C-ring.
The main feasibility issue with this cemented sliding sleeve concept was fracture initiation pressure through the cement and
into the formation without perforated holes. Significant laboratory testing was conducted which predicted fracture initiation
pressure to be similar to that encountered in openhole or even lower. Fracture initiation pressures were closely monitored
during several field installations and confirmed that perforations were not needed to initiate fractures in the formations.
This paper describes TAP Completions, how the TAP valves work, and how the valves performed. Information on a TAP
Completion with 6 layers is presented in detail and an overview of all installations to date.