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.

No abstract

Smart Auto Gas Lift (AGL) refers to a downhole system that utilizes gas from a gas zone or a gas cap in a well to lift oil below or above the gas zone in the same well. This paper illustrates a novel AGL intelligent completion design approach including candidate screening, pre-drill feasibility study, sensitivity analysis, and followed by the completion installation and production operation practices for the first two (2) successfully completed AGL wells in Malaysia. In the candidate screening process, a novel design approach was used based on a 3D numeric single wellbore dynamic model forecasting method. Firstly, candidate screening was performed for the application suitability of AGL in the candidate reservoir. The key screening factor includes the identification of the source of AGL gas, either from the associated overlaying gas cap or independently from another layer of non-associated gas, estimation of gas pressure and oil pressure, estimation of volume of available AGL gas and longevity of gas reserve throughout oil production life, and considering the reservoir structure and drive mechanism. Secondly, single well prediction modelling analysis was performed to evaluate candidates' dynamic performance on production rate, water cut, gas oil ratio (GOR) profile and pressure depletion over time. This is to make sure designed AGL completion will meet expected various production dynamic responses during the entire life of well. The next step is to conduct production snapshot nodal analysis for the appropriate choke size design for AGL downhole flow control valve. Those dynamic results from the single wellbore prediction model becomes important input for nodal evaluation to simulate changing reservoir conditions at different stages. Finally, various sensitivity analyses on layer properties and valve setting depth are followed to ensure that the AGL valve choke sizing design range is flexible enough to cover expected reservoir uncertainties and to be effective over the entire well life. Based on above design and analysis approaches, a specified range of AGL valve choke opening were designed for T field candidate wells and smart AGL completion system was installed successfully and safely in two wells by end of 2014 without any health, safety and environmental (HSE) issue and AGL related non-productive time (NPT). The production and well test data were available for production performance surveillance, and the dual permanent downhole gauge system (measuring pressure and temperature in both the tubing and the annulus) at gas zone enabled the continuous auto gas injection monitoring at real time basis. This paper discusses AGL well design approaches, justifications, best practices and lessons learned regarding completion installation, well clean up and production operations to give a general guideline for AGL implementation in this area in the future.

Tango Field, located offshore Sabah in East Malaysia, is a mature field which has been producing oil and gas for more than forty years. This field has many fault blocks, thus creating barriers to fluid and pressure communication between different fault blocks. Furthermore, the reservoir sands are turbidite sands which are difficult to correlate across the whole field. Being fan lobes, it is not easy to target these sands in drilling development wells. As part of the campaign to improve recovery and sustain production, two infill wells were drilled during 2014, by sidetracking two existing wells from the Tango-B Platform, which is located in the western part of the field. The target reservoirs are M1 and M2 sands, which still carry some upside potential based on the latest review of the field performance. To properly target and penetrate these sands in the planned wells, the Reservoir Mapping While Drilling LWD (DDEM) tool, in combination with standard triple combo LWD (Logging While Drilling) tools, was deployed. This is to ensure that the well trajectory stays within the targeted sands and the bed boundaries are detected long before the drill bit exits the sand body. Unlike previous deep reading LWD resistivity tools, the DDEM tool is a Deep Directional Electromagnetic Propagation tool which has the capability to see about 30 meters laterally beyond the wellbore. While drilling the first well, the target sands were penetrated as planned. However, there was a pleasant surprise where a new hydrocarbon sand was detected by the DDEM tool about 10 meters below the wellbore. The DDEM reservoir mapping software was used to image the newly found sand body. Based on this new finding, the drilling Bottom Hole Assembly was pulled back and the hole was side-tracked to target this new sand, which was successfully penetrated and completed. This new sand, which would not have been discovered with standard LWD tools has increased the well production by a factor of two or more. Being a turbidite sand, it was not picked up on the surface seismic section. The reservoir mapping software technology, together with the deep sensing resistivity imaging LWD tool, was instrumental in finding the new hydrocarbon sand which has substantially increased the production of Tango Field.

Effective exploitation of the thin oil rim in the Gunung Kembang field is particularly challenging because of the huge size of the overlaying gas cap, and the thickness of the oil rim varying between 25 to 40 feet gross pay interval, not to mention the sizeable water aquifer underlying the reservoir. Horizontal wells were implemented since 1992 to enhance oil recovery by reducing gas and water coning, nevertheless, oil recovery still remain around 3%. As the pressure is depleting, horizontal wells revealed to pose higher risk than before, just like in the second stage of horizontal drilling in 2004, where water breakthrough and total loss occurred. The plan to add more horizontal wells to add recovery was coincided with POD commitment to deliver gas by gas cap blow down. This paper presents a team effort to formulate optimization strategy for maximizing oil recovery and revenue while delivering gas as committed in POD. Integrated reservoir characterization that comprises of carbonate depositional study, and reservoir simulation was conducted to best manage not only the drilling location but also number of wells and production strategy for next horizontal wells. Carbonate depositional study using existing logs and core data revealed the best oil potential zone in Baturaja formation in terms of porosity and permeability. Meanwhile, reservoir simulation grid was aligned with the zonation from carbonate deposition model, after that the performance of existing 10 wells was history-matched to develop an improved strategy. Sensitivity analysis conducted demonstrated that locating horizontal oil wells in the upper oil rim near the gas oil contact proved to be the best strategy for depletion of the oil rim. Among five scenarios developed, one final scenario was selected to accommodate both oil recovery optimization and gas cap blow down. This scenario includes eight additional horizontal oil wells while utilizing their produced gas to accommodate gas commitment, without drilling another gas well. Oil recovery is expected to rise to about 8% while gas is being delivered according to POD. Introduction Gunung Kembang Field is located in the South Sumatera Extension area of Medco E&P Indonesia working areas. This field was discovered in 1987 with GK-1 drilling and was put on production in June 1988. This carbonate reservoir has a thin oil column of around 40 ft sandwiched between thick gas cap of about 117 ft and water aquifer with the drive mechanism is mainly gas cap drive with weak water drive. Currently, cumulative production of this field has reached 3.8 MMSTB of oil and 50 BCF of gas with 10 wells, in which 6 of them are horizontal well. Because of apparent thin oil column, vertical well performance were upset by quick gas coning and water coning, thus encouraging the need for horizontal wells. Started in 1991, three horizontal wells were drilled; they are GK-7, GK-9 and GK-10. Excluding the production of GK-10 well which entered poor quality rock in the horizontal section, the cumulative production from other 2 horizontal wells until the end of 2004 is 2.5 MMSTB-indicating the success of horizontal well performance. Further simulation study was conducted by third party to maximize oil recovery in Gunung Kembang field by drilling 5 horizontal wells. Based on those simulation study, another horizontal drilling campaign was executed in 2004 by side-tracking 3 existing vertical wells, GK-1, GK-3, GK-6 to be GK-1 Horizontal Well (HW), GK-3 HW and GK-6 HW. Unfortunately, only GK-1 horizontal is considered successful, meanwhile the other two having problem in early water breakthrough, and total loss. Thus the oil recovery is still remains low at about 3% from total Original Oil in Place.