Greater Bongkot North is a gas field located in Gulf of Thailand and on production since 1993. Most of the old wellhead platforms (30%) lack remote well test facilities which requires personnel visits for any well test measurement. Often, well testing in these platforms get lower priority compared to other operations in a matured field. This project implemented artificial intelligent (AI) technique to estimate gas rate from other available engineering and geological parameters. A new approach using machine learning was applied to estimate gas production rate where actual measurements are not available. Actual production well test data was used to train the model. Input parameters used were: Surface facility information Fluid properties Production condition Geological setup A blind test on the subset of historical data showed a level of confidence (R2) value of 0.93. This provided confidence to proceed with a full field pilot. A pilot was conducted during January to May 2018. The area of pilot was spread across various geological, operating and surface condition setups to reduce sampling bias. The pilot demonstrated the following use cases: Improved prediction accuracy in wells with no recent test, achieving primary object of model. Detection of well behavior changes: The model could detect changes in well behavior without human intervention much before the trends become obvious for engineers to detect. Improved potential estimation in wells with leaks in wellhead chokes where conventional analysis followed in Bongkot is not possible due to improper wellhead shut-in pressure measurement. Improved efficiency with production allocation: The conventional method requires significant time (40-80 person hours per month) to make the data available for production allocation. This can be shortened significantly by use of this method In essence, this project demonstrated the potential use of artificial intelligent to improve efficiency in a matured gas field operating under marginal conditions.

Low-permeability sandstone formations in deviated exploration wells were drilled and completed in 2013 in northeast Thailand. Reservoir simulation modeling indicated that a well would not produce as a result of the tight formation. Hydraulic fracturing was then considered, and a plan was adopted to use this method to improve the well's production using reservoir simulations. Microseismic fracture monitoring was implemented to correlate data with actual fracture propagation to understand the formation's geomechanics. The fracture design methods were combined with completion and cleanout strategies to help improve well performance. The fracturing design was incorporated into a complete operational procedure, along with contingency plans, a decision tree, and an integrated communication plan, to allow for possible contingencies. Careful planning, fluid testing, and a fit-for-purpose completion design resulted in a successful hydraulic fracturing operation. The microseismic equipment was installed and monitored during the fracturing operation to provide actual fracturing propagation noise signals. This paper presents the well fracturing technology, operational procedures, and microseismic technology used to better understand reservoir behavior and geomechanics characteristics. The geophone installation and surrounding control on location provided minimum noise interference for more accurate actual fracture propagation data. The computer program then forecasted fracture propagation. Comparisons between actual fracture propagation and the simulated fracture design allowed the operator to better understand subsurface parameters and characteristics for building the reservoir database. The operator was also able to forecast fracturing dimensions to help prevent water production zones. This significant reservoir information can be used for field development to maximize hydrocarbon production. Fracturing technology and seismic technology were combined to improve the probability of successful hydrocarbon production. Microseismic results demonstrated the actual fracturing plane dimensions and dynamic fracture propagation, and the fracturing computer program provided fracture simulation dimensions and direction. Combining these technologies allowed the operator to obtain more reservoir data for future field development.

TX 75083-3836, U.S.A., fax +1-972-952-9435 Pru Krathiam (PKM) is a small onshore, unconsolidated sandstone reservoir in Thailand containing medium heavy oil with viscosity of approximately 50 cp. Fluvial channels supplied sediments to form mouth bar sands in lake with sand thickness of 1 to 3 meters. In its 25 years of natural depletion, the field has achieved merely 1.7% recovery factor. The difficulty in production has been attributed to aquifer support combined with unfavorable mobility, and sand production. Secondary and tertiary recovery methods have been investigated, with the assumption that sufficient sand-control could be implemented. Basic EOR screening reveals that thermal and chemical methods could be appropriate for this challenging field, in addition to infill drilling. Further investigation by means of a history-matched full-field reservoir simulation model indicates that chemical flooding has the advantage over cyclic steam stimulation (CSS) in this type of reservoir and reservoir fluids. Polymer flooding using high molecular weight polyacrylamide gives significant recovery improvement. Its implementation will give an extra benefit to the field which has high initial water cut as polymer solution contacts the unswept regions of the reservoir. The oil recovery appears relatively insensitive to rock-polymer properties, i.e. adsorption, inaccessible pore volume, and residual resistant factor. Further study shows that adding alkaline and surfactant can increase oil recovery beyond polymer flooding. Generic properties of oil/water/ASP system e.g. interfacial tension and surfactant adsorption were used. ASP flooding performance seems sensitive to these properties, so extra care must be taken when designing the process. The fundamental constraint of polymer flooding and ASP flooding operation is the cost of implementation. CSS, on the other hand, still faces up severe problems with reservoir heterogeneities and high initial water saturation. Reservoir heterogeneities cause steam to disperse unevenly, leading to poor heat distribution. High water saturation results in much of the heat being absorbed by water. Mobility improvement by viscosity reduction is small for medium heavy oil and is slightly overcome by the effect of steam condensation. IntroductionPru Krathiam (PKM) is one of the fault-bounded dip closures located on the eastern flank of Phitsanulok Basin. The discovery well, PKM-A01, encountered viscous oil with 17-19 o API in Lan Krabu formation. Lan Krabu formation was deposited in the fluvio-lacustrine environment: fluvial sediments were transported from the east, and were deposited as mouth bar sands in the lake to the west. Evidences from grain size distribution and fossil indication match the notable characteristics of fluviolacustrine sediments, which are low energy aqueous deposition and the absence of marine fauna. In some areas, features such as levee, back swamp, coal and rootlets can be found. These are indications of shallow lacustrine deposits with frequent variations in the water...