An operator spudded an extreme high-pressure/high-temperature (eHP/HT) well in the Mediterranean Sea, offshore Egypt, in 2012. To achieve the well objectives, it was necessary to set 28-in. surface casing at 1183 m, which was the deepest casing point used for such a large casing size in the offshore Mediterranean. The depth and size of the hole required presented numerous challenges, including but not limited to managing the variable deck load, hole stability during long casing running operations, logistic challenges for fluids resulting from significant washouts, etc. One of the main challenges was related to achieving zonal isolation objectives for this section. These objectives were to cover the casing shoe with good quality cement and to achieve zonal isolation at the seabed and top of casing to help avoid future unexpected shallow flows to the surface. Meeting both of the objectives was paramount for resuming further operations. Typically, both of these objectives can be achieved in a single stage using lead and tail slurries. However, because of the long hole section and significant washouts (up to 300%), bringing cement up to the seabed would require pumping approximately 4,400 bbl of lead slurry and 380 bbl of tail slurry, which is equivalent to approximately 11,700 ft 3 (500 MT) of dry cement, and 16 hr of cement pumping time. To help mitigate the risks associated with a single-stage operation, it was decided to perform the job in two different stages. The first stage was designed to isolate the casing shoe and lower sand body by performing a lead and tail primary cement job. The second stage was a liner top squeeze. This was a multistage operation using several cement types of various particle sizes. The top of the liner was successfully squeezed, and the objectives of the cementing operation were met. This paper describes the challenges experienced and solution for completing the cementing job, which could be valuable for designing similar offshore high-pressure/high-temperature (HP/HT) wells.

This paper is to highlight the engineering advance method had been successfully applied in Gulf of Suez, Red Sea, Egypt, well, January 2014. This new method enables to use the same slot for several slot recovery operations rather than only one slot recovery. The Deflecting Conductor Shoe is made as a subsea diverting tool. The conventional size ranging from 24” to 30” depending on the platform's dimensions and restrictions. Using a DCS with bigger sizes designed to match the platform's levels to result in the minimum angle at seabed, and to permit for conductor movement horizontally. Also to avoid the magnetic effect at the seabed a mechanical gyro used to determine Azimuth. The spacing between the conductors at the seabed is designed in pattern to allow for best anti-collision results, and more number of wells. The modification on the DCS is by the controlled azimuth of exit, the diameter and the new conductor inclination at the seabed. The most important feature in this design is the ability to engage with a spear from the inside in the future, and turn it to the desired direction considering collision with nearby wells, and with applying the method of drill and drive the risk of hitting nearby wells had vastly decreased and the ability to correct the well path increased by using motors. Using this design will push the platform life within the increased production and in the same time saves the cost to install standalone wells or to establish new platforms extensions which enhances the investment cost for wells on old fields. This means an overall revival of old platforms and old slots whilst making the best use of reservoir potential reserves which were difficult to be achieved with minimal cost. Using this new design, each slot on the platform can be used for multiple slot recoveries, up to five. This design is a modification on the methodology of using the DCS tool which is still conventionally used by major Oil and Gas companies.

Over the past 4 years, there have been several stuck incidents during installation of liners and casing in some wells in Shell Petroleum Development Company (SPDC), Nigeria. In most cases, the sticking mechanism was identified to be differential due to high pressure over balance across some depleted sand intervals. Attempt to free the casing or liner string was successful in few of the cases, while in others, it resulted in either cementing the casing in place at the stuck depth and deploying contingency option where they exist or going through the long, rigorous and expensive process of fishing, plugging back and sidetracking. Investigations into these incidents pointed mostly to the casing centralization. During casing installation, a good standoff is required to keep the casing string away from the wall of the well bore to avoid differential sticking and achieve good cement placement. On the other hand, excessive centralization could lead to increased drag force particularly in deviated wells with the attendant risk of not getting the casing to bottom. Prior to casing installation, it is a standard practice to run simulation on centraliser spacing to achieve an acceptable standoff. Bow spring centralizers are commonly used especially for 9-5/8" casing installation and experience has shown that placement of these centralisers to achieve the acceptable standoff in order to avoid differential sticking as well as good cement distribution has led to having a casing string packed with centralisers thereby increasing the drag force. It therefore became imperative to develop a strategy for optimum centralizer placement in order to achieve both the acceptable standoff to avoid differential sticking and minimum drag. This paper discusses the approach taken to achieve this acceptable standoff with minimum drag force using a combination of Spirolizers and Bow spring centralisers and its impact in reducing the risk of differential sticking.

This paper highlights a successful cement job in which more than 1,300 bbl of cement slurry was pumped to help cement the longest 9 5/8-in. casing in a highly deviated and washed out wellbore in the Gulf of Suez (GOS). This novel slurry design aided efficient cementing across a massive salt section, while mitigating the risks associated with using a multiple-stage cementing tool in highly deviated wells. To access most of the reservoirs in the GOS, operators must drill through a salt section with a thickness sometimes greater than 1000 m. This section is covered with 9 5/8-in. intermediate casing, which is generally cemented in two stages using a multiple-stage cementing tool. Conventional salt slurries of 15.8- to 16-lbm/gal are generally used to cover the salt section. Any failure with the multiple-stage tool can lead to expensive remedial work and can cause salt instability resulting from longer exposure, which can lead to salt creeping or loss of the well. The success ratio of multiple-stage tools is not high, especially in highly deviated wells; therefore, it was necessary to find a new approach to help mitigate the risks associated with using multiple-stage tools. High-strength, low-density (HSLD) slurries have been successful in replacing conventional 15.8- to 16-lbm/gal slurries across the production zones. With this in mind, lightweight salt slurries were designed to replace conventional salt slurries across the salt section. Because this is the longest intermediate casing in the GOS to date for the operator, it was logistically favorable because the lightweight slurries helped reduce the amount of dry cement required to meet the rig capability. The cost of the multiple-stage tool, additional dry cement, dry-cement-transportation costs, and rig costs for waiting on cement (WOC) for the second stage were either completely eliminated or minimized with this solution, resulting in a total savings in excess of USD 100K.

Abstract The main subject of this paper will be to outline the field experience achieved with a new type of well profile and directional drilling system. Reducing the cost of well construction has been a driver for many new technologies. The lean casing profile introduced by Eni about a decade ago was a successful step towards lowering the drilling and completion cost in the vertical, top hole section. Automated vertical drilling tools have been the technical enabler of such concept. Recently Eni has moved further towards an even more radical "Extreme Lean Well Profile". This paper gives a brief insight into the well design concept and the enabling technology behind it. The drilling technology is based on the well-known automated vertical drilling system, which has been enhanced by the capability to drill an enlarged hole size below a casing, without compromising the verticality and hole quality. In the main part of the paper two field applications, in the Mediterannean Sea offshore Egypt, are described. The paper will also cover the lessons learned especially from the second of the first two field applications. The extreme lean well profile and automated vertical reaming technology can provide value to several drilling campaigns not only through the reduction of well construction cost. Another major benefit is the ability to run an intermediate casing string, if required because of difficult well conditions, and still arrive at the same diameter of casing in the reservoir. The completion concept as well the enabling tool technology is very unique and has not been available to the industry until recently. Introduction It is the ultimate purpose of any oil and gas well to help develop a reservoir as soon as possible and with the maximum rate and volume of hydrocarbon recovery. Reaching the reservoir horizon quickly and safely requires, in many cases, the application of some smart well construction techniques. This is true even in the upper sections of the hole. A straight and smooth borehole curvature reduces the inherient risks of running casing strings. In addition, such geometry provides the optimum conditions for being able to drill the horizontal section to the maximum reach. At the same time, when the trajectory is of a "gun-hole" shape and quality, less annular space has to be reserved for the casing string running operation. If this concept is realized through all or most of the hole sections, the well will be less cascaded than with the conventional approach. This type of "Lean Casing Profile" allows for faster well construction, fewer consumables and an increased operational efficiency. The "Lean Casing Profile" concept was first introduced to the oil field in the early 1990's. Based on the economic success achieved, the operating company has recently decided to drive this concept even further. The new "Extreme Lean Casing Profile" reduces the annular gap even further than with the previous method. In a way, the extreme lean shape is an importants step towards the visionary monobore hole, yet much more realistic to do as of today. As with the previous method, this new well construction scheme is based heavily on the application of an enabling downhole technology that guarantees the required straightness and precision. This can be accomplished by means of an automated rib-steering directional drilling device that is fully operated in the sliding mode. In a hole's vertical section, eliminating drillstring rotation improves borehole stability. In order to facilitate the extreme lean casing well construction, some new dowmhole directional drilling systems had to be created, such as an automated steering system with an integrated reamer and an automated rib steering device with a special diameter. The new well construction process and made-for-purpose tools has been field-tested in a series of wells in the Egyptian Sea where operating conditions were critical due to hole stability problems.