This paper presents a case study of the first horizontal well in ADX field, Malay basin, which was drilled with an objective of maximising oil production from one of the minor reservoirs. In longer term, this well will be used as water injector once the reservoir pressure has been depleted, as part of the pressure management strategy in the field. To optimise the current production and the sweep efficiency at a later stage, a minimum of 500-m lateral length was planned for this well.The target reservoir contains gas cap without any aquifer and is currently produced with natural depletion. The plan was to place the horizontal well as close as possible to the base of the sand and as far as possible from the known Gas-Oil-Contact, to delay gas breakthrough and to use it as water injector at a later stage. An upper TVD limit was determined in which the wellbore should avoid to keep certain distance from the gas cap. However, the formation in the target location was expected to have a dipping-up trend, which could significantly limit the vertical space to steer the lateral section and achieve the minimum target length.A full suite logging-while-drilling measurement including deep directional resistivity which enabled 3D detection of approaching boundaries; combined with a proactive well placement method executed by collaborative experts from multidiscipline teams were used to address these challenges. As a result, the horizontal well was placed accurately within 0.5 m from the base of the reservoir along a 500-m lateral section; achieved with 3D geosteering decisions to avoid both the base and the upper TVD limit. Following the success of this first horizontal well in the field, another horizontal water injector well targeting a very thin reservoir was drilled successfully in the same field by applying similar methods and processes.

T-Field, located offshore East Malaysia, is a matured oil field that beganits development in the 1970s. Conceptual geological model generally illustrated this field as retro-gradational turbidite setting. The major reserves are contained in the stage IVD sequence, which is of late Miocene in age. The gross oil-bearing interval is about 300 m thick, divided into three(3) groups of sands (U -Upper, M-Middle and L-Lower stage IVD). As the "low hanging fruits" exist but are limited within this 40 years old matured field, drilling along the reservoir bedding plane was introduced as the best way to optimise the oil recovery in this field, where maximum reservoir-wellbore contacts and lower drawdown are expected to be achieved. It is commonly known that the turbidite channel has enormous geological complexity and therefore presents great challenges for successful horizontal well placement. The discontinuity of sand packages, highly anisotropic environment with the presence of thinly laminated sand and the lateral heterogeneities in horizontal zone are the biggest challenges in the implementation of this new drilling approach. Therefore, good well planning and right geosteering decision during drilling are crucial to achieve the well objectives. A reservoir mapping-while-drilling technology with capability to map the multiple sand layers in larger scale (up to 30m Depth of Investigation) was utilised to provide a clear picture of the reservoir structure during well landing and after entering the reservoir to stay inside the reservoir sweet spot for optimum production. This paper captured the first job in South East Asia in developing horizontal well placement in turbidities environment. It elaborates the highlights, success story and lessons learnt in using the latest technology which was proven as the most advanced geosteering and reservoir-scale mapping tool. This technology has not only enabled the drilling of 600 m-MD oil column, doubled net-to-gross ratio of sand penetrated and doubled the oil production of target reservoir but it has also helped the asset team in proper reservoir characterization and redevelopment planning.

Some of the hydrocarbon-bearing sands in ADX field, Malay basin, have been identified as minor reservoir with an average sand thickness of less than 3 m. Thus, reservoir development has become challenging. One of the effective ways to develop these reservoirs is by drilling highly deviated or horizontal wells.After long production, one of the minor reservoirs in ADX has become highly depleted and was in critical need of pressure maintenance. Based on the field study, waterflood was chosen to manage the reservoir pressure. This reservoir is distributed widely in the field, with thickness ranging from 1 to 3 m. Because of the sand thickness, the most efficient method is to place an injector well horizontally. However, placing a horizontal well in this depleted thin sand poses significant challenges for the drilling operation. These include accurately landing at the target sand, avoiding premature exit due to geological uncertainties and the thin reservoir, and managing the borehole pressure to avoid differential sticking of the bottomhole assembly. For formation evaluation, high-angle effects such as anisotropy, close vicinity to shoulder beds, and lateral property changes complicate quantitative interpretation.A full suite logging-while-drilling measurements including near-bit gamma ray, average and deep directional resistivity for boundary detection, azimuthal density, neutron porosity, and formation pressure, combined with a proactive well placement method executed by collaborative experts from subsurface, drilling, and geosteering teams were used to address these challenges. As a result, an injector well was placed optimally in the thin target reservoir for a length of 300 m, as per the objective. Modeling of the high-angle well was also conducted to extract the true formation properties and to address the highangle effects on the measurements to improve the quantitative petrophysical evaluation. Comprehensive predrill planning, the drilling execution that included 24-hour real-time monitoring to steer the well, and post-well evaluation and modeling yielded lessons learnt, best practices, and recommendations for drilling and evaluating similar wells.

Acquisition and interpretation methods to optimize horizontal wells have been broadly introduced in the industry nowadays. It has evolved from the basic and conventional technology such as gamma ray and average resistivity to the latest deep directional boundary detection method. Technically, all methods can be used to place a horizontal well. But the amount of information available for interpretation and real-time decision making such as measurement sensitivity, vertical resolution, and depth of investigation are different and unique for each technology, which could lead to different results in the placement of the well and thus the production profile. Horizontal well targets also vary from thin beds, thin oil rim in a single sand or across multiple sands with high angle cross section, laterally heterolithic reservoir, to massive thick reservoir; each of which have their own characteristics that can be interpreted from the log measurements. However, high angle effects such as anisotropy, shoulder beds or bed boundary will affect the measurements which may then affect the well placement interpretation accuracy and execution efficiency if not anticipated or understood well. Therefore, a proper risk assessment and technology selection in the early planning stage is critical, as most operators will need to allocate the budget to deploy the selected technology and methods. This paper presents a horizontal well risk assessment workflow from geosteering and formation evaluation perspectives based on the well placement experiences and geological environments in South East Asia. The workflow provides guidelines and general references for horizontal well technical analysis during the early planning stage which will help to optimally manage the risk associated with horizontal well projects. It involves risk assessment based on the geological condition and well objectives, followed by feasibility modeling phase to compare different methods and technologies, and finally the technology selection process to achieve the well objectives. Introduction Despite horizontal drilling costing almost double compared to vertical well expenditure, the concept has become popularly adopted in the oil and gas industry, beneficially increasing the production rate in mature or brown field. The planning and execution of a horizontal well has many challenges mainly related to directional control, geological uncertainty and reservoir characterization. Horizontal wells approach the target formation nearly parallel to the bedding plane; hence, it is also correlated to a small TVD windows target. The inability of seismic to interprete micro fault and reservoir variations along the target well will significantly reduce the net to gross ratio inside the pay zone. Many of horizontal well's failures are resulted from these two issues hence requires the operator to plan both the well path and geological target more accurately. Well Placement, which includes a planned interactive geosteering along the wellbore using geological data, combines technology and process with collaboration of multi domain disciplines. The well placement method is well known for years as a proven concept that has led to the success of horizontal drilling. Year to date, there are 5 known types of well placement method which is commonly used in South East Asia region;Geometrical drilling. The aim of this method is to drill conventionally with directional assembly to reach the reservoir target. Geometrical drilling is employable if the reservoir target is more than 100 ft thick and has many offset wells drilled around the target zone. The risk of using this type of horizontal well remains big as the survey EOU (Ellipsoidal of Uncertainty) could be an issue if drilling a long well. Therefore, proper advanced survey calculation method has to be applied in order to reduce survey uncertainty.

X Field is a carbonate platform setting in Central Luconia, Malaysia. The field faced declining trend of gas production due to early water rise. Seismic attribute shows that the rising water was assumed to be related to the water being drained through crossflow into the possible karst feature, which may have acted as conduit located near the existing production well bore. Two horizontal infill wells were planned in this field with the objectives to accelerate the gas production, and to investigate the uncertainty on the current gas water contact (GWC) movement, karst feature and fracture identification in single run LWD. The horizontal well placement strategies were set in different workflows as some key reservoir parameters are still uncertain. Several scenarios were made based on real-time reservoir characterization and observation, then they were translated into different production performance profiles. To achieve those well objectives, a new technology approach was proposed that consisted of the latest reservoir mapping while drilling technology with the capability to map the reservoir structure and fluid contact within 35m depth of investigation. This was combined with the full suites of log measurement including neutron, density and sonic data for secondary porosity measurement to support the real-time petrophysical and well placement decision making. The two horizontal infill wells were planned to stay close to the top of carbonate and to avoid the water contact as much as possible in order to optimize the gas production. The second well would depend on the first well reservoir observation result. On this case study, the application of reservoir mapping technology while drilling has successfully demonstrated the well placement as close as 7m TVD below the reservoir roof and mapping the gas water contact at 30m TVD below the trajectory. The actual GWC was detected 25m shallower than prognosed, so the finding of this first well has led to the decision to eliminate the drilling of the second well, which resulted in a cost saving of more than USD 20 million. Other than that, the qualitative result from reservoir mapping tool provided a new understanding of carbonate reservoir modeling, which confirmed the interpretation, current GWC and reservoir heterogeneity characterization both vertically and laterally. This strategy could be replicated in other carbonate reservoirs to delineate current gas water contact without physically penetrating it. Karst and secondary porosity interpretation were used for completion optimization and to maximize the production.