The Jasmine Field sandstone reservoir described in the paper is highly compartmentalized, has a sand thickness of about 30-40ft, reservoir pressure is supported by a strong aquifer, and most wells have high productivity. However, in the particular fault block of interest, a gas cap is present, which is normally not present in other fault blocks. This reduces the oil sand thickness to about 20 ft, with a big gas cap above and water below. To efficiently produce the oil rim in this area, a horizontal well was required, with an electrical submersible pumps (ESP) to aid lift. Since ESPs don't typically handle gas very well, the challenge was to ensure the well is economic by preventing premature gas breakthrough, and hence increase oil recovery. The Autonomous Inflow Control Device (AICD) is an active flow control device that delivers a variable flow restriction in response to the properties (viscosity) of the fluid flowing through it. Water or gas flowing through the device is restricted more than oil.When used in a horizontal well, segmented into multiple compartments, this device prevents excessive production of unwanted fluids after breakthrough occurs in one or more compartments. The JS-06 well was drilled with almost 2000 ft horizontal length within the original thin oil column, with gas on top and water below. AICD flow loop testing, performance modelling, candidate selection, and completion design for this well was focused on gas production control, given that gas production was the main concern. Post implementation and production, gas production has been controlled very well compared to the base case conventional completion. The gas oil ratio (GOR) observed from nearby wells was within the normal production range, which has allowed more oil to be produced from the JS-06 well. The production results observed were consistent with modelling and laboratory flow testing, thereby increasing confidence in the methods employed in designing the AICD completion for the well and in AICD modelling and candidate selection. The successful implementation of AICD in this well has opened up another similar opportunity, which are currently being evaluated for the same application

Tangguh is a large gas producing development located in Bintuni Bay, in the Papua Barat province of Indonesia, some 3000 km east of Jakarta, the capital city of Indonesia. Gas production from the Vorwata Field and LNG export from the Tangguh LNG facility started in 2009. The field and the LNG facility are operated by BP. The Vorwata development consists of 14 wells drilled from two normally unmanned platforms. The wells were predrilled prior to completion of the LNG plant and are completed as 7" monobores. They are perforated conventionally and are limited to 240 MMscfd each due to erosional considerations. Production from the field is currently 1.3 Bscfd; this rate being limited by the throughput capacity of the Tangguh LNG plant. During the initial testing phase following completion and prior to start-up, the wells were limited by the infrastructure to a maximum rate of 100 MMscfd. Pressure transient analysis (PTA) of the data obtained during this test phase indicated that most of the wells had high mechanical skins. A reservoir preservation study showed that these high skins were caused by near wellbore damage and could theoretically be reduced by producing the wells at higher rates. Following start-up and establishment of stable plateau production, a rigorous well clean up and maximum rate testing program was carried out. The wells were flowed at rates up to 240 MMscfd and pressure build up (PBU) tests were subsequently carried out to evaluate any improvement in reservoir deliverability. The analysis of the post maximum rate test PBU data showed that the skins were reduced on average by 40% in each well.

The Jasmine Field is a mature stacked-sand oil field that has been on production since 2005. One of the biggest current challenges is to locate remaining oil accumulations. Seismic mapping, material balance and reservoir simulation studies provide pointers to promising locations, but can never guarantee accuracy. Pilot wells offer a means to appraise identified locations before committing to drilling horizontal wellbores. A pilot well is often used in Mubadala Petroleum drilling campaigns as part of an overall strategy to extend the field's life by continuing to locate and tap remaining oil accumulations. Collaboration across subsurface teams leads to decisions on pilot well locations. In most cases the pilot well appraisal objectives will be to confirm the structural position, to identify fluid contacts or to assess depth uncertainty, especially in areas where there is no well penetration or in significantly updip locations. These appraisal objectives apply to shallower and deeper horizons as well as to the target reservoir itself, and in Jasmine there is a strong record of accomplishment of successfully locating remaining oil by means of such appraisal. It is critical therefore, that well planning is tailored so as to accommodate the appraisal objectives as well as the eventual production target. Two case studies are presented, illustrating different approaches to using pilot wells prior to placing horizontal wellbores in Jasmine field. In the first case, the horizontal production wellbore was planned to develop an updip region of the target reservoir, to access remaining oil, with additional pilot well appraisal objectives in both shallower and deeper zones. The location for the new horizontal well was confirmed and this dual-role pilot/producer well not only succeeded in reducing depth uncertainty for the new horizontal wellbore, but also identified additional reserves in other reservoirs. In the second case an appraisal pilot well was used to investigate a downdip region of a depleted reservoir. Material balance assessment had indicated that the volume accessed by the updip producer was larger than suggested by the static model, which might have resulted in water encroachment from downdip, causing the appraisal location to water out. However, seismic imaging identified potential barriers between the updip and the proposed downdip appraisal location, which would have prevented water encroachment from downdip. The pilot appraisal well was required to distinguish between those two possibilities.

In many infill development scenarios, including those in shallow, heavy oil intervals, horizontal wells are required, and are positioned as high as possible within the reservoir. In other cases, horizontal wells are drilled to tap undeveloped oil in thin reservoirs with high uncertainty due to seismic resolution limitations. Mubadala Petroleum successfully deployed a new advanced Geosteering technology to overcome these technical challenges. Although Geosteering is often conducted in this Mubadala Petroleum Field, there was a need to mitigate the additional complications of well positioning in complex fluvial reservoirs using innovative approaches and technologies. The solution was a new multi-layer bed boundary detection scheme using a deep azimuthal resistivity distance-to-boundary tool. This was coupled with a novel sophisticated high definition stochastic seismic inversion, providing the ability to resolve multiple bed boundaries above and below the tool, clearly understand formation dip and improve understanding of the boundary azimuth angle. We present two case studies illustrating different applications of the new technology: The seismic inversion provided a clear image of the reservoir sand, however the new multi-layer bed boundary detection technology enhanced the ability to steer through the structural heterogeneous variations in the upper parts of the sand normally beyond seismic resolution of the data. The multi-layer bed boundary detection with high definition inversion provided valuable insight during the real-time horizontal drilling, which helped in maintaining the well in 75% high quality reservoir pay zone.For the horizontal drilling of the thinnest part of the reservoir where pre- and post-conventional seismic inversion volumes were insufficient to provide detailed stratigraphic and geometrical images, we successfully used the new technology to overcome the difficulties. In this approach and after landing the horizontal well into the sand, multi-layer bed boundary detection was used to navigate through the channel sand and maintain the well within the reservoir. This was assisted by streaming real-time high-definition stochastic inversion into the asset team's G&G software, which provided a highly accurate sand thickness, revising pay sand thickness from 15 feet to 25 feet and improving the accuracy of the volumetric estimation. As a result, the horizontal section was successfully navigated in 100% of the section and within high quality reservoir. Furthermore, we used this accurate data for a post-job recalibration of seismic and updating of the geological model and hence improving reserves estimation accuracy. This is the first Mubadala Petroleum implementation in this basin of multi-layer bed boundary detection and streaming high definition stochastic inversion, providing vital information to real-time execution and to post job improvement of the field model.