Quick clean up and dramatic improvements in reservoir producibility have been achieved in gas wells located offshore Egypt. These wells were drilled and completed using an engineered drill-in fluid system. The fluid formulation was carefully designed and extensively tested in three different laboratories prior to the field applications to help ensure reproducibility of the data and to verify the non damaging characteristics of the fluid. These tests were conducted under simulated downhole conditions to help ensure fluid compatibility with the reservoir rock minerals and natural fluids. To help minimize fluid invasion while drilling in the payzone section, the optimal concentration and particle size distribution (PSD) of the suspended bridging material were selected and maintained during the field applications. The PSD of pure ground marble was selected based on the reservoir rock morphology and average pore size to establish effective bridging near the wellbore and help ensure quick lift-off of the filter cake. A high-density calcium chloride / calcium bromide brine blend (14–14.5 lb/gal ~ 1.68 sp.gr.-1.74 sp.gr.) was used as the base fluid to achieve and maintain the required fluid density without additions of insoluble weight material. Optimal concentrations of non-damaging temperature-stable polymers were used to provide suspension and filtration control. The gas reservoir section was drilled and completed in several wells with the new system. Productivity index and flow rates exceeded the operator's expectations without any stimulation treatments. Substantial savings were realized in terms of rig time and well completion costs. This paper presents the laboratory and field-generated data and discusses the key issues in designing and monitoring the new drill-in fluid during the field applications. Introduction One of the keys to optimizing wellbore connectivity and retaining the natural reservoir rock permeability is to ascertain and quantify the complex, often interdependent physical interactions and chemical reactions occurring downhole between the reservoir rock fluid and minerals and the drill-in / completion fluids used 1,2,3. Some of the most common ways of damaging a formation include pay zone invasion and plugging by fine particles, formation clay swelling, commingling of incompatible fluids, movement of dislodged formation pore-filling particles, changes in reservoir rock wettability, and formation of emulsions or water blocks. Once one of these damage mechanisms diminishes the permeability of a reservoir, it is seldom possible to restore it to its original condition. Reservoir characterization and sensitivity studies were carried out to identify and quantify the geologic parameters that could influence the producibility of the Miocene sandstone gas reservoirs in an offshore field in Egypt. The field is located in the Mediterranean Sea, 35 miles north of Port Said City, at the northern entrance to the Suez Canal (Figure 1) The fluid sensitivity study included thorough examination of the rock morphological and mineralogical composition 4,5. Core analysis data was generated by specialized core laboratories for core plugs from carefully selected sections of the gas zones. The natural reservoir fluid was also analyzed to establish their chemical make-up. These data helped determine the reservoir's potential for formation damage problems. Based on the information and the reservoir rock data, a brine-based drill-in and completion fluid was designed and tested, under simulated downhole conditions. These tests were conducted in Baroid's Houston lab, Baroid's Cairo lab, and Eni E&P Milan lab to ensure reproducibility of the lab test data and verify the non damaging characteristics of the selected additives and fluid formulation.

TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractThe following-up of drilling operations in "real time" from a remote location has been on the wish list of some drillers for quite a long time. In recent years, this has become a reality with phenomenal advances in digital technologies, satellite communications, remotely controlled systems, and collaboration centers that allow locations in different parts of the world to follow up on an operation on a round-the-clock basis.The primary objective for the exploration drilling of oil and gas wells is to find and develop new energy sources that can meet the energy demands of the future. It is also universally accepted that this objective must be met safely and efficiently.Real-time operations go a long way toward ensuring safety for the oilfield; the ability to remotely monitor operations avoids the need for experts or other non-essential people on location. This reduces the exposure risks associated with travel or rigsite presence for a number of people. The safety factor extends beyond the physical transportation or presence of individuals at a work location because, by monitoring subsurface pore pressure trends, shallow flow hazards can be detected early and a recourse taken. The well is essentially under the discernible watch of several experts at critical points ensuring the delivery of a safe and efficient well.Several other operational benefits can be realized from real-time operations. This paper discusses several of the tangible gains realized from this type of operation and the future it holds for its users.

Significant effort usually goes into deciding the optimum completion and generating production forecast of new wells. However, due to uncertainty of certain reservoir parameters, the completion decision may not be optimum and may result in non-economic well. We focus in this paper on answering the following questions:(1) what is/are the optimum perforated interval(s)?, and (2) what is the optimum economic production rate for vertical wells in water drive oil reservoirs?. Obtaining the right answer for these two questions will give us the opportunity to make the right completion decision. Several models are available to predict the critical coning rate. In many cases, the calculated critical rates are too low, and for economic reasons, wells are frequently produced at higher rates. In this paper, we present a new approach for the determination of the economically optimal production controlling parameters from water drive oil reservoirs. In this approach, static and dynamic models are constructed to model the well and the surrounding reservoir properties. Two experimental design techniques are used to test the uncertainties in reservoir parameters and identify the most important optimization parameters. The model is linked to an economical model to calculate certain economic indicators. Then an optimization process is applied to find the optimum production controlling parameters to achieve maximum economic oil recovery. Many cases were tested with this approach. Then, the optimization results were compared with the critical rate correlations' results. It was found that the chosen drawdown and perforation interval(s) provided safe operation range for water cut, while allowing reasonable economic gain. Therefore, this new approach is recommended over the available critical rate coning models, to define the optimum production controlling parameters to achieve optimum economic recoverable oil volumes in water drive oil reservoirs.

TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractThe following-up of drilling operations in "real time" from a remote location has been on the wish list of some drillers for quite a long time. In recent years, this has become a reality with phenomenal advances in digital technologies, satellite communications, remotely controlled systems, and collaboration centers that allow locations in different parts of the world to follow up on an operation on a round-the-clock basis.The primary objective for the exploration drilling of oil and gas wells is to find and develop new energy sources that can meet the energy demands of the future. It is also universally accepted that this objective must be met safely and efficiently.Real-time operations go a long way toward ensuring safety for the oilfield; the ability to remotely monitor operations avoids the need for experts or other non-essential people on location. This reduces the exposure risks associated with travel or rigsite presence for a number of people. The safety factor extends beyond the physical transportation or presence of individuals at a work location because, by monitoring subsurface pore pressure trends, shallow flow hazards can be detected early and a recourse taken. The well is essentially under the discernible watch of several experts at critical points ensuring the delivery of a safe and efficient well.Several other operational benefits can be realized from real-time operations. This paper discusses several of the tangible gains realized from this type of operation and the future it holds for its users.

An integrated reservoir study was initiated to look for new opportunities in East Zeit field. The working team managed to construct the full field static and dynamic models. The main challenge during the history match phase was the high complexity of the structure, range of uncertainties, and the model running time. The team managed to understand unconventional reservoir aspects such as:(1) The reservoir pressure was sharply decreases as production increases. Then, when the reservoir was abandoned as a depletion drive reservoir the pressure started to increase up to initial reservoir pressure without any intervention.(2) The performance of few wells completed in the above mentioned reservoir was similar to the performance of wells in active water drive reservoirs.Comprehensive work in the history match has been done to calibrate the model and explain the different phenomena in the field. The team explained the pressure increase in the depleted reservoir that it was due to the reactivation of faults which became non-sealing. This resulted in communication with another active water drive reservoir and natural miscibility process. The study recommended adding new off take point in the reservoir to confirm the concept. So, a new well was drilled and confirmed the study conclusion and managed to add more reserves and production in the rejuvenated reservoir after 12 years of shut in. Currently, constructing complete field development plan is in progress to maximize the recovery factor. Reservoir monitoring even after abandonment, especially with unconventional reservoir aspects, is very important to discover new opportunities and maximize the recovery. These opportunities should be managed through the integrated reservoir simulation studies to minimize the risk and cover the uncertainties.