Drilling operations became more expensive and complicated day by day due to many reasons affecting directly the daily drilling cost. One of the most effective cost reductions was the fixed cutter bit solution which effectively achieved higher drilling progress and reduces overall well cost. Also, in some cases PDC bit may raise the well cost due to slow down in the penetration rate or stopped drilling to retrieve mechanical parts from the hole due to bit fatigue and followed by extra trips for junking or fishing operations. The present study focuses on most of the factors affecting fixed cutter bit design, drilling parameters that influence the bit cutting structure wear and led to the bit poor progress. All previous PDC bit mathematical models used before for determining the cutters wear value not considered real methodology on rig site to assure cutters wear and gives a proper decision to terminate the PDC bit run. Study investigated four mathematical models had calculated the PDC cutters wear using the influences of the rock strength, rock temperature and mechanical drilling parameters. These models are theoretical and applied within the lab test devices, most of models not achieved significant benefit to use in rig site applications. New model had developed to compute PDC wear value as function of surface torque arises from the friction between the drill string, bit interaction with well bore and rock on bottom. Both resistance created by the string and bit are converted to output data realized by the gauge in front the driller in rig floor and mud logging unit. Analog or digital data reflects the torque obtained from rotating the bottom hole assembly (Drill pipe, string stabilizer and bit) against the wall of hole and formation strength. Mathematical model calculates the theoretical torque for string tool joint, stabilizer and PDC bit cutters allocated in nose up to gauge area. In reality, when BHA rotates off bottom torque created is representing the summation of string tool joint and stabilizer. An additional torque realizes on surface when BHA on bottom and WOB applied then this bit torque value will be compared by model bit torque. This later obtained bit torque percentage that represents the cutters wear value preoperational to cutter height. New mathematical model had created visual analog graphs will help to take decision when stop drilling and terminate the PDC bit run. Field validation test had run in two main concessions in Egypt Western desert and Gulf of Suez with total 6 PDC bit runs using different bit size, type, cutter sizes and different bottom hole assembly (Rotary-steerable). The filed results showed significant correction in cutter wear magnitude between the model calculation and field runs, this error factor less than 10% in hard formation and less than 20% in medium to soft formations. Author set the correction in model and treated in easy way to be used on field by driller and drilling engineers to help them how to determine the PDC bit cutting structure wear value.

Wells in challenging environments are known for their high cost with targets not reached, and often abandoned. HPHT wells fall in this category and in Lower Mediterranean Sea this was not an exception. After a few wells drilled in an offshore HPHT area, with advanced techniques and alternatives being tried on well after well, Eni through its foreign affiliate decided to use a combination of Eni's continuous circulation (CC) valves, (Eni Circulation Device - E-CD) and the Micro-Flux Control (MFC) method. Eni calls the combination of CC with the precise measurement and control of the flow and pressure from the well, within a closed loop through a rotating control device (RCD), as: Eni-Near-Balanced Drilling (ENBD). With this new drilling method, a well in the HPHT area reached all the targets for the first time. Wells in this area face the usual kick-loss scenario, with significant non productive time (NPT) and adding hundreds of days to drill a well. The goal for using the E-CD was to avoid pressure and temperature fluctuation while drilling, by maintaining the annulus as stable as possible, and the MFC would provide a clear picture and manage the bottomhole pressure (BHP) within the downhole pressure limits, pore and fracture. Previous attempts to improve drilling were made using just RCD, then a continuous circulation system and later on the E-CD valves were used together with the RCD on other wells, but, even though improvements were seen, those were not enough to ensure reaching the final targets. It was only when the MFC method was added that success was achieved. The paper describes the operations and results obtained by the ENBD system and its benefits in terms of NPT and kick quantity and size reduction. Comparison with the previous wells where the targets could not be reached clearly shows the significant advantage of using the system, compared to conventional drilling. Reduction in risk and increased control over the entire drilling process, in an environment with extremely narrow margins, were paramount to a successful outcome. Introduction Exploratory wells are in principle classified as challenging ones due to the inherent uncertainty relative to the downhole pressure limits, pore and fracture pressures, as well as formation surprises that are not clearly mapped from seismic. In addition the exploration frontier is moving increasingly towards more difficult environments, and it is no surprise that many exploratory wells have been abandoned before reaching the planned TD, therefore failing to meet its commercial or technical objectives of collecting valuable data about possible reservoirs and hydrocarbon reserves. Despite many improvements to drilling systems, such as the top drive, steerable directional systems, mud motors, Pressure and Logging While Drilling (PWD and LWD), Continuous Circulation Devices (CC), Rotating Control Devices (RCD), it has been the arrival of a closed-loop Managed Pressure Drilling (MPD) method that has provided a significant step change in drilling performance. For the first time the pore and fracture pressures can be determined very accurately and safely while drilling, in real-time, and as a consequence the mud weight can be properly adjusted and managed, avoiding loss circulations, stuck pipe, and low ROP. The industry loses an enormous amount of time trying to solve these problems, which very often leads to misunderstanding that the well's technical limit has been reached and abandoned unnecessarily.

In many Brownfield developments, toward the end of a well's life cycle, the primary production zone(s) commonly waters out or depletes, or the well sits idle with no alternative means of returning back to production. At this stage, as a normal course of action, the wells are re-evaluated for potential reserves that might have been bypassed during the original completion. For zones that do not appear promising or could be marginal in terms of delivery, the recompletion costs can be prohibitive. It is in such situations that "cement packer" completions performed rigless in offshore environments provide an economic alternative to workover operations. This technique can be cost-effective and has the potential to increase the producing life of a well. This paper describes the successful application of a "cement packer" to recover bypassed reserves located above the production packer in an offshore field in the Mediterranean Sea. The technique allows zonal isolation between the various upper zones by placing cement slurry in the production tubing and casing annulus.Conceptually, it might appear simple to perform such a job, but the planning and execution must be well formulated to ensure well integrity is maintained at all times. In this case history, the challenges of executing the job were examined from many different angles (i.e., high angle well, small platform, short weather window for operations, and multiple job sequences). The average cost was only 20 to 60% of conventional workover jobs, which is a savings of up to USD 400,000. The production results have also been encouraging. These successful results have revealed opportunities for reactivating many more shut-in wells with bypassed reserves that are currently considered economically marginal. BackgroundWell BB-1 was drilled in 1997 during the exploratory drilling phase of the Petro-Said field in the Mediterranean Sea, offshore Egypt (Fig. 1). The well was completed in 2005 in the Kafr el Sheikh Anomaly-4 (An-04) level from 1710.0 to 1755.0 m with an internal casing gravel pack to help prevent formation sand production. With time, the primary production zone (An-04) depleted and watered-out, and it remained idle for further development. There were a few limited shallower zones (An-02 and M1) higher up in the wellbore, above the production packer, that appeared worth investigating. These zones were small sands with possibly low static bottomhole pressure; otherwise, scarce information was available regarding their production capability. The upper completion string consisted of a 4.5-in. chrome tubing (Fig. 2) run to surface on a 9 5/8-in. completion packer set at 1648 m. A landing nipple was available in the string at 1645 m and a subsurface safety valve at 215 m. The lower completion included a gravel-pack packer set at 1675 m and a gravel pack screen and gravel across the perforated interval at 1710 to 1755 m.The recompletion of this well using an offshore workover rig would have entailed killing the well, isolating the lower completion, pulling the upper co...

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.

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 SpA, the major Italian oil and gas company, 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 a concept. Recently, this oil company 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 and 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 and the enabling tool technology are very unique and have not been available to the industry until recently.