In Asia Pacific region, there are many thinly bedded reservoirs which are composed of interbedded porous and permeable sands with variable proportions of thin silt and clay beds. These reservoir sand bodies range from millimeters to tens of meters in thickness. Though the reservoirs are highly permeable, reservoir heterogeneity caused by silt and clay laminations affect recovery and sweep efficiency. The typical way to test such formations is to use full scale well testing, even for relatively thin zones. In the Gulf of Thailand (GoT), a Tubing Stem Test (TST) is widely used to test each individual zone for reservoir parameters. During a TST, quartz gauges are run on wireline and the selected zone is perforated. While wireline Formation Testers (FT) have also been increasingly used in the GoT for measuring formation pressure, mobility and collecting reservoir fluids, more advanced FT tools, e.g. dual packers and Downhole Fluid Analyzers (DFA) were recently introduced to test each zone to help defining reservoir characteristics in more detail. A single probe FT deployed for pretests and fluid sampling can be used to obtain transient data during the shut-in periods after sampling in relatively thin zones. The data from these Interval Pressure Transient Tests (IPTTs) can be used to interpret reservoir parameters such as vertical to horizontal permeability ratio and horizontal permeability. This paper discusses the uses of such smaller scale pressure transient data (single probe, dual packer formation testers) and full scale well testing using a simulation model and actual field data from the GoT. First, a single well simulation model is used to investigate the effects of thinly bedded shales at different scales on pressure transient data. The actual field data were then analyzed to obtain reservoir parameters and compared with core and PVT lab results. This paper also investigates the use of deconvolution applied to pressure transient tests of different scales to understand the effect of reservoir parameters using simulated and field data. Introduction Thinly Bedded Reservoirs in the Gulf of Thailand In the Tertiary Basins of the Gulf of Thailand and Northern Malay Basin, thinly bedded hydrocarbon sandstone reservoirs have been encountered in several geological settings. In the northern Gulf of Thailand, Kra Basin, subaqueous lacustrine fan delta sandstones of between 1 to 4 feet have developed as a result of episodic deposition. In the Southern part of the Pattani Basin adjacent to the Narathiwat High, thinly bedded reservoirs of less than 1 to 7 ft were deposited in marginal marine, tidally influence estuarine channel fills settings and also in more proximal fluvial crevasse splay deposits.

The development of marginal volumes in the Jasmine field is part of Mubadala Petroleum's overall strategy to extend the field's life. This development is accomplished by progressively exploiting increasingly challenging prospects. This paper highlights two case studies to illustrate how Mubadala Petroleum has successfully developed marginal prospects to unlock the Jasmine field's remaining potential. Prospect identification begins with integrated subsurface studies focusing on contingent resources. Several studies were conducted to determine the right technology to mature these marginal prospects. These prospects often involve the requirement to drill Extended Reach Drilling (ERD) wells. This is due to the fact that some platforms are slot constrained, such that wells cannot always be drilled from the nearest platform. One of Mubadala Petroleum's solutions was to drill a horizontal well with a completion that uses an Autonomous Inflow Control Device (AICD) to optimize and enhance oil production. This combination of AICD and ERD horizontal wells has proven successful in the Jasmine field's continuing development. Two wells in this case studies were drilled during the 2018 and 2019 drilling campaigns, illustrate how marginal volumes are developed in the Jasmine field, with each case having unique objectives and challenges. In 2018, one horizontal well was drilled, with an aim to enhance recovery efficiency in the viscous oil reservoir. The well was drilled close to the top reservoir, AICD devices were installed in conjunction with a sand screen to delay water breakthrough, and the well has been in production for two years. The overall strategy was effective in delaying water breakthrough. In 2019, a horizontal well was drilled to develop a relatively small 14ft oil rim below a thick gas cap reservoir. This well was the longest ERD well in the Gulf of Thailand. The well was also successfully drilled and geosteered at 4-5 ft TVD below the gas cap. AICD's were installed to balance the gas cap expansion and aquifer support to optimize oil production. The well has produced at a stable oil rate of 500-600 bbls per day with minimal gas and water production, up to the present date, confirming the validity of AICD technology in reducing the production of unwanted fluids. The AICD has been shown to play a significant role in optimizing production in reservoirs with small oil rims and thick gas caps. AICD completions also help to enhance production recovery from viscous oil reservoirs. Moreover, ERD drilling has improved the feasibility of several remote prospects and minimized the slot availability constraint in the Jasmine field.

The Jasmine Field began production in 2005 with initial estimated recoverable reserves of 7 MMbbls.

Pressure transient analysis has been known as an important tool to properly characterize a reservoir. The scales of measurement for different testing methods depend mainly on their radius of investigation, i.e. how far pressure changes/disturbance can be seen into reservoirs. In a large reservoir, a full scale testing method such as a Drill Stem Test (DST) is required to test enough reservoir volume for flow assurance purposes. To test for the reservoir extent, a production test is required to reach reservoir boundaries.In recent years, there have been tremendous developments for short period testing methods. The Formation Tester (FT) is one of the tools that are used to evaluate reservoir fluid properties and acquire pressure transient data from both dual packer and single probe configurations. With the current Downhole Fluid Analyzer (DFA) technology, reservoir fluid properties such as composition, Gas-Oil-Ratio (GOR), in-situ density, and viscosity can be obtained in real time. These insitu fluid properties can be used to analyze pressure transient data for reservoir permeability, skin factor, and reservoir heterogeneity; and as a result, the DFA serve to push IPTT applications to another step forward. This paper will specifically focus on the application of DFA for IPTT purposes and also a continuation of several published papers which discussed the use of different scales of pressure transient data. The results from this paper will mainly focus on the use of single probe and dual packer IPTT to obtain reservoir properties in thinly bedded reservoirs with waxy crudes from the South East Asia region. The viscosity variation from oil based mud filtrate to reservoir fluid during the pump-out and its effect on the pressure derivative will be discussed using actual examples to demonstrate this point.The end results may contradict traditional testing methods on the use of virgin reservoir fluid properties for pressure transient analysis. Hopefully, this paper might open another option when FT is deployed together with the current DFA tool for quick and effective reservoir evaluation in thinly bedded reservoirs which are often encountered in many parts of the world. TX 75083-3836, U.S.A., fax +1-972-952-9435