TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAdditionally to proven deterministic modeling techniques, like numerical reservoir simulation, so called "data-driven" modeling techniques can support petroleum engineers in reservoir management tasks.Data-driven modeling means that the underlying relationship among measured data is calculated by the model itself and no a priori knowledge of the physical system governing the data behavior is needed.Neural Networks are such data-driven models and "learn" the underlying model from data. Neural Networks are computational models broadly inspired by the organization of the human brain. The most important features of a Neural Network are its abilities to learn, to associate, and to be errortolerant.Many papers have been published during the last years demonstrating the wide range of possible applications of Neural Networks in Exploration & Production. An example in reservoir management issues will be presented, with regard to optimizing the injection-production ratio in a Middle East reservoir.

The long term zonal isolation is an important factor to be considered while designing cement slurries for deep High Pressure, High Temperature (HPHT) gas well. Conventional heavy weight cement systems which have been used in the past have often had to sacrifice the set cement mechanical properties such as compressive strength, permeability, and porosity, to provide a slurry design which is stable, mixable and pumpable. Changes in downhole conditions in terms of temperature and pressure can induce sufficient stresses to destroy the integrity of the cement sheath which will cause long term gas migration and sustained annular pressure. Hence, the set cement mechanical properties have to be carefully designed in order to withstand the downhole stresses especially the ones generated during the well testing and fracturing treatments. This paper will discuss the selection and the Novel Flexible and Expanding cement system and details one well case history of nine wells which is part of the upstream agreement with Saudi.

Many "poor" gas prospects-particularly ultralow-permeability and porosity unconventional rocks such as tight sand-become economic success when hydraulic fractures are created in the pay zone. The fractures allow a single well bore to contact many thousands of square feet reservoirs. Using swellable packer technology has mechanically simplified fracture job. Using multiple packers ensures the entire zone is treated; or in other words, knowing where the fracture fluid goes once it exits the casing, and how each set of fractures is isolated from another is a key in a successful hydraulic fracture design. Lukoil Saudi Arabia started an exploration campaign in the Rub’Al-Khali Empty Quarter in 2006 targeting Non Associated Gas and nine wildcat exploration wells have been drilled and evaluated. It was found during the early stages of the exploration that the gas accumulations in LUKOIL Saudi Arabia exploration Area (Block-A), were typically trapped in tight to ultra-tight reservoirs (see Fig. 1). These gas discoveries in the Empty Quarter have occurred in High Pressure and High Temperature (HPHT) horizons at depths between 12,000 and 20,000 ft, where the stress and temperature are extremely high in addition to micro-Darcy levels of reservoir permeability. This has made the exploration activity more challenging. Figure 1 Location of Project Area in Rub Al-Khali Desert

When control drilling interbedded formations due to lost circulation challenges, Bi-Center bits often fail to open the hole to the expected drill size. Possible causes include inconsistent downhole weight on bit due to formation changes, lateral and torsional vibration. Each leads to the pilot of the Bi-Center bit drilling an oversized hole which results in the bit drilling off-center, giving an undersized hole. To combat this, a patented double profile Bi-Center bit was developed. Its elongated pilot section includes a unique midreamer section which improves lateral stability due to more balanced cutter forces. Also, the mid-reamer provides an additional gauge section immediately below the reamer which in conjunction with the pilot gauge has proven to reduce tilt and keep the pilot bit centralized, providing more consistent full gauge hole. Additionally, vibrations generated by the drillstring are common during the hole-opening process. These affect not only the drilling performance but also the quality of the wellbore. A unique eccentric stabilizer, ideally located in tension in the BHA, provides vibration dampening in the drill-string. The V-Stab interrupts harmonic modes vibration as well as reducing the magnitude of shocks due to its unique geometry. Caliper logs from field trials of a 10–5/8 × 12-/14" CSDX6413S-B1 Bi-Center bit with a 10–5/8 × 12" vibration dampening tool demonstrate excellent hole opening performance and improved borehole quality. In contrast, logs for conventional Bi-Center bits run with the vibration dampening tool showed inconsistent hole opening and poor borehole quality in the same application. This paper describes the benefits of the unique combination of these new technologies, presenting detailed drilling performance data showing how they resulted in significant performance improvement and cost savings in southern Saudi Arabia. Introduction Lukoil Saudi Arabia drills some challenging exploration wells in southern Saudi Arabia. These wells have encountered several difficulties involving severe borehole stability problems. On the well "D", the 13–3/8 casing was planned to be set on top of Sulaiy Formation at around 9,258 ft. However, the 16" phase was unable to reach this depth, having to be stopped at a much shallower depth of 7,625 ft because of lost circulation problems Additionally, the 13–3/8" casing could not be run to 16" hole total depth due to restriction in the hole. The 13–3/8" casing was set at 6,865ft and the rest of the 16" open hole was finally covered by 11–3/4" expandable casing that was set at 7,617ft to ensure that the 9–5/8" casing setting depth could be reached as per the drilling program Fig.1. Since the 11–3/4" expandable casing has 11.286" drift ID after expansion, a hole opening tool was required to open the hole from the casing pass through size to 12–1/4" hole size, to allow the 9–5/8" casing to be set properly.

Scale formation and deposition (CaCO3) in production facilities is a problem encountered in the Ghawar Field in Saudi Arabia. The scale deposition causes production loss and safety hazards. Downhole scale inhibitor squeeze treatments have proven successful in controlling this scale accumulation. However, weak producers (low oil rate and high water cut wells) could not be squeezed due to the difficulty anticipated in re-starting production from these wells because of the high volume of water normally needed to squeeze the inhibitor into the formation. Starting in 1994, an alternative method (the encapsulated inhibitor treatment) was tried for selected weak wells. This paper presents the design of the encapsulated inhibitor treatment, treatment procedure, a field case history with scale inspection results, economical analysis of this treatment versus the regular downhole treatment and the future plans. To-date, more than ten treatments have been performed in Saudi Arabia. Regular visual inspection of selected wells revealed no scale accumulation up to 24 months after the treatment. Current plans are to treat more wells for further evaluation. Introduction Calcium carbonate CaCO3 scale is the most common scale encountered in the Ghawar field production wells. Its deposition in surface and subsurface equipment causes loss in oil production and major operational problems. The scale control program was started in the Ghawar Field in 1986, and since then, conventional scale inhibitor squeeze treatments have been successful in controlling scale accumulations. Saudi Aramco field experience has shown that weak oil producers, especially high water cut wells (WC >70%), when treated using a conventional scale inhibitor squeeze, require several reviving attempts before the wells can be put back on production and in some cases the wells might remain dead. This is mainly due to the hydrostatic head created by the large treatment fluid volumes normally pumped during a conventional treatment where the inhibitor is squeezed into the formation to a predetermined radius. In 1994, a new scale inhibitor treatment "Encapsulated Inhibitor Treatment" was introduced to Saudi Aramco. The main advantage of this treatment is the placement of the treatment fluids in the rathole rather than squeezing it into the formation. Therefore, the encapsulated scale inhibitor treatment is suitable for the weak wet oil producers with high water cut. To-date, more than ten wells in the Ghawar Field and an offshore field have been treated with the encapsulated inhibitor, without any difficulty in bringing the wells back on production. Some of these wells are being closely monitored for rescaling by performing regular visual inspections. To date none of these treated wells have shown scale redeposition after up to two years following the treatment of the first well. P. 295^