As the country pushes for higher output from its emerging unconventional sector, nature is pushing back. To get better results, operators there are increasing their reliance on technology. What Does the New Silk Road Mean For Oil and Gas? Executives from two of Asia’s largest national oil companies declared China’s Belt and Road Initiative project a driving force behind their shifting priorities to diversify the world’s energy mix. Total’s Laggan Tormore project claimed the International Petroleum Technology Conference (IPTC) Excellence in Project Integration Award at the 10th IPTC in Bangkok, Thailand.
What Does the New Silk Road Mean For Oil and Gas? Executives from two of Asia’s largest national oil companies declared China’s Belt and Road Initiative project a driving force behind their shifting priorities to diversify the world’s energy mix. The country continues to step up its delivery of shale gas, but has a long ways to go to meet the government's target. Total’s Laggan Tormore project claimed the International Petroleum Technology Conference (IPTC) Excellence in Project Integration Award at the 10th IPTC in Bangkok, Thailand.
Kamkong, Paphitchaya (PTTEP) | Karnjanamuntana, Thamaporn (PTTEP) | Prungkwanmuang, Weera (PTTEP) | Yingyuen, Jakkrich (PTTEP) | Oatwaree, Dejasarn (PTTEP) | Amornpiyapong, Nichakorn (PTTEP) | Khositchaisri, Patcharin (PTTEP) | Tivayanonda, Vartit (PTTEP) | Wongsuvapich, Dutkamon (PTTEP) | Tongsuk, Soraya (PTTEP)
Lunar field is a marginal gas field located in the Gulf of Thailand. A significant portion of reservoir sands is currently categorized as Additional Zones of Interest (AZI) which is not accounted in reserves. As for this kind of sand, the conventional petrophysical evaluation alone cannot certainly distinguish between hydrocarbon and water in the porous medium. The alternative method (dT LogR) for formation re-evaluation is therefore considered in attempt to reduce uncertainty in fluid classification and reveal hidden hydrocarbon potential from these AZIs.
There are 2 phases in verifying the validity of dT LogR method. Phase I: dT logR method (Ref.
Phase II: The production test data from perforated AZIs in phase I and the well correlation were then incorporated in dT LogR assisted log reinterpretation. Additional 13 gas-potential AZI candidates were identified for 2nd perforation test to prove the correctness of the recalibrated petrophysical model. The results showed success in model improvement of which its accuracy increased to 61% and no high water production was observed in any of them.
After using dT LogR method to assist petrophysical evaluation, a total of 469 metres of unperforated AZIs were reconsidered to be productive gas bearing formation. In other words, 22 BCF of gas reserves and 873 MSTB of condensate reserves from these upgraded AZIs were added. In addition, it is foreseen that the remaining AZIs of other platforms are to be further reevaluated and therefore improves the confidence in reserves booking and field development planning of Lunar Field.
In conclusion, the dT LogR method is a very useful tool for Lunar Field to significantly reduce uncertainty of fluid classification which in turn provides lots of benefits in gas field management adding immeasurable value to Lunar Field.
Phummanee, Sutthipat (PTT Exploration and Production Public Company Limited) | Rittirong, Ake (PTT Exploration and Production Public Company Limited) | Pongsripian, Winit (PTT Exploration and Production Public Company Limited) | Phongchawalit, Natthaphat (PTT Exploration and Production Public Company Limited)
The objective of this paper is to demonstrate the implementation of downhole water drain (DHWD) technique to improve gas recovery factor for bottom-water-drive gas reservoir in the multi-thin reservoirs system in Arthit field. This technique was selected as an alternative method to defer water loading in the wellbore by preventing early water breakthrough meanwhile enhancing gas expansion. Project planning, operation, and performance evaluation are the gist of the discussion here.
Candidate selection was the critical first step to the success of DHWD technique. The suitable wells require a gas-water contact reservoir at the upper part of the well and totally depleted reservoirs below it. After identifying candidates, bottomhole pressure survey was performed to investigate the reservoir condition for reservoir simulation. Both gas and water layers above and below the gas-water contact were perforated as designed. A plug was set between the perforated gas and water layers to isolate the flow. This allows gas to be produced to surface while water flows downwards to the depleted reservoirs.
The key parameters used in evaluating the effectiveness of DHWD technique are incremental gas recovery and water breakthrough time. According to the production history of existing gas-water contact reservoirs in Arthit field, massive water production generally starts to intrude after 1.35 months of production at which water-gas ratio increases above 50 STB/MMscf. As a consequence, the gas production sharply declines and eventually ceases to flow. The water breakthrough time of the two trial wells in which DHWD technique was applied is significantly slower than the field average. One was observed water breakthrough after 2.05 months and the other was after 5.40 months of the production. Gas EUR gain is the difference between the EUR when applying DHWD technique by declined curve analysis and the expected EUR of conventional production by statistical method. The results from the two trial wells indicate that DHWD technique can significantly improve the EUR by 110% and 871%.
Downhole water drain is a groundbreaking technique that can be practically implemented to enhance gas recovery of bottom-water-drive gas reservoirs. This technique is recommended for gas field as an alternative strategy since it yields substantial additional reserves gain while required only a small additional cost from the additional perforation of water sand and permanent bridge plug.
When the joint development of extreme-high-temperature tools began in May 2014, the goal of the collaboration was to eliminate wireline in wells with temperatures over 175°C. Historically, the need for wireline was driven by the requirement to identify hydrocarbons, measure reservoir properties, and book reserves in high-temperature wells; this was accomplished by using a wireline string consisting of gamma ray (GR), resistivity, formation-density, and neutron-porosity sensors. Because of the 175°C temperature limits of the available LWD technology at that time, there was no viable option to log these wells while drilling. This resulted in valuable rig time spent on additional trips to change out bottomhole assemblies (BHAs), mitigate temperatures, and run wireline to gather this data. This also increased the exposure to nonproductive-time (NPT) events, stuck wireline tools, or loss of data if these tools did not reach bottom. Thus, the requirement arose to log these wells while drilling to reduce days per well and improve data collection. To this end, the joint development of extreme-temperature LWD tools was initiated and staged in two phases.
Sompongchaiyakul, Penjai (Department of Marine Science, Faculty of Science, and Center of Excellence on Hazardous Substance Management, Chulalongkorn University) | Bureekul, Sujaree (Department of Marine Science, Faculty of Science, and Center of Excellence on Hazardous Substance Management, Chulalongkorn University) | Sombatjinda, Siriphorn (BMT Asia Co., Ltd)
More than two decades that the Gulf of Thailand (GOT) has been installed with petroleum hydrocarbon production platforms, currently over 400 platforms were installed and operated. Since mercury is a common contaminant in petroleum hydrocarbon production in Southeast Asia, minimal risk and environmental integrity should be concerned. Mercury concentration in surface sediment collected from the Gulf of Thailand in 2003 (89 stations), 2012 (174 stations) and 2013 (45 stations).
Sedimentological characteristics, readily oxidizable organic carbon and calcium carbonate were determined. All analyses were carried out in our laboratory using cold vapor atomic absorption spectroscopy. The results show an increase in trace amount of mercury in the Gulf's sediment. Average concentrations of mercury in surface sediments in the lower GOT collected in 2003, 2012 and 2013 were 24.4±9.00, 34.9±21.5 and 41.4±15.3 μg/kg dry weight (carbonate free basis). It is coincident to an increment in the number of platforms for natural gas exploration and production in the Gulf of Thailand. Spatial distribution of mercury in the sediments indicates a clearly linked to the exploration, development, production, and processing in petroleum and gas operation. Although the elevation of mercury level in the GOT's sediment does not showed high risk yet, treating and recycling of mercury contaminated substances generated during production are required in order to minimize the health risk in consumption of seafood collecting from the GOT.
The availability of high quality seismic data is of critical importance in trying to unravel the complexities of subsurface geology. This paper illustrates how proper selection of seismic acquisition parameters and data processing techniques can successfully overcome geological difficulties and minimize uncertainties when exploring for hydrocarbons in the northern part of Block G11/48, Gulf of Thailand, without compromising safety and cost efficiency.
Fluvial and fluvio-deltaic sediments of early to mid Miocene age in low relief faulted structural traps constitute the most common hydrocarbon habitat in the area of investigation. Amplitude support in identifying potential targets is also proven by nearby discoveries. To fully evaluate the exploration potential of this area, a 3D seismic acquisition campaign was successfully carried out using a high-end seismic vessel and without HSSE incidents.
The Nong Nuch dataset was acquired using a 10 deep-flat towed 5.1 km streamer configuration with triple sources to increase cross-line resolution and reduce operational time. This long streamer length relative to the target depth provides necessary information to Full Waveform Inversion and Q-tomography in order to correct push-down effects in broadband anisotropic Pre-stack Depth migration. The dataset also helps to obtain high accuracy velocity model, de-multiple and quantitative interpretation. This acquisition and processing approach significantly improved the ability to image thin reservoirs and correct push-down effects and energy absorption due to gas clouds or unconsolidated sea floor channels.
The large streamer spread and deep tow did not create any major problems throughout the acquisition. The implementation of broadband acquisition and leading edge processing techniques resulted in good signal to noise ratio as well as high vertical and horizontal resolution with minimal acquisition footprint. In addition, long offset data acquisition contributes to successful attenuation of short and long period multiples. Channel-like features and fault plane reflections are very clearly imaged in the dataset, helping to better understand of the depositional environment and structural setting of the area. Severe push-down and abnormal amplitude absorption effects were significantly corrected and compensated by building a high resolution, Full Waveform Inversion (FWI) derived velocity model as well as application of reflection tomography and Q-tomography techniques. Thus, definition of potential traps beneath gas clouds has significantly improved.
Easy oil is no longer low hanging fruit for oil and gas operators, and drilling targets are becoming increasingly ambitious, which results in escalation of the well trajectory complexity. This accordingly spirals the well and completion costs. To overcome this situation, technology must play a role to reduce cost, increase efficiency and ensure safety at all times. Conveyance is the key for any data acquisition and well completion activities. Historically, conveyance methods for data acquisition and perforation in highly deviated or horizontal wells required drill pipe or coiled-tubing methods. These methods are time consuming, labor intensive, require a larger equipment footprint, with possible HSE risks involved. Mubadala Petroleum in Thailand has seen a significant increase in horizontal and high deviated wells over the past few years. The wireline tractor technology has been used for the first time in Mubadala Petroleum's Thailand operations during the drilling, initial completion and workover intervention operations, and it has been a game changer for Mubadala Petroleum in Thailand in terms of reducing rig time, well cost, and most importantly minimizing the HSE risks.
Over the past few decades, the oil and gas industry has developed the technique of drilling horizontally through the reservoir to maximize the surface contact area of the reservoir, to gain higher recovery and production. However, one downside from this technique is that it has become challenging and costly to perforate or to obtain measurements in this horizontal environment, as gravity will no longer support the wireline tools to reach to the bottom of the well. Wireline Tractor technology has played an important role to overcome this challenge. It reduces time, cost and will improve data quality as well as increase wellbore coverage. The wireline tractor functions with an electric over hydraulic power relationship, using its drive/wheel sections to push the passenger tool downhole as the cable is spooled off the unit allowing the tool to reach the end of horizontal or deviated wells without deploying drill pipe or coiled tubing conveyance methods. With this principle, any job that is typically run on electric wireline in a vertical well can be efficiently done in a horizontal or deviated well using wireline tractor.
Material presented in the paper will be from actual operations, examples being tractor conveyed wireline logging tool and 4.5in Outer Diameter (OD) 90 ft heavy long perforation gun in single tractor operations. It will also display the operational efficiencies increases and risk reduction being obtained.
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
Leelasukseree, Cheowchan (Chiang Mai University) | Sangkhaphan, Phutchara (Electricity Generation Authority of Thailand) | Chanwised, Natthawat (Electricity Generation Authority of Thailand) | Pipatpongsa, Thirapong (Kyoto University)
Mae Moh, Lampang, a small town in northern Thailand, approximately 600 km far from Bangkok, contains a large, open-pit, lignite mine. The mine is managed and operated by the Electricity Generation Authority of Thailand (EGAT) to provide 15 million tonnes of coal per year for its power plants. In 2011, EGAT selected a pit wall 300 m wide (called Area 4.1) to conduct a large-scale experiment to better understand how pit wall displacement responded to undercutting. A monitoring system was installed to measure surface and subsurface movement. During the rainy season in 2016, Area 4.1 experienced a number of remarkable events related to precipitation. The main sequence of slope undercutting to excavate lignite and back filling of Area 4.1 was completed in summer 2017. Area 4.1 was continually monitored and studied during the large-scale experiment, including deploying a ground-based radar system. Inverse velocity technique, using measured movement data from the radar, was applied to predict slope failure and warn site operators. In the 2016 rainy season, Area 4.1 was warned the failure many times, but the undercut slope was visually stable. The undercut slope displayed stick-slip behavior each time the alarm sounded, and the area was appropriately evacuated. The following dry season, Area 4.1 was mined for lignite and backfilled. The mining and backfilling were done as planned in May 2017. The stability of the supported undercut slope Area 4.1 has been satisfied since the following rainy season.
Mae Moh mine is the largest open pit mine in Thailand. It is located in Mae Moh, Lampang, a small town in northern Thailand, approximately 600 km from Bangkok. The mine is managed and operated by the Electricity Generation Authority of Thailand (EGAT) to provide 15 million tonnes of lignite a year for EGAT’s 10 coal-fired power plants.
Khosravi et al. (2011) used physical models in the laboratory to investigate the behavior of undercut slopes. The study showed that undercut slopes were stable if the undercut span width was narrower than the maximum undercut span width. The maximum undercut span width is greatly affected by the rock strength and the slope angle. In 2011, EGAT then proposed a field experiment in the mine to further study these behaviors (Mavong et al., 2013 and 2014). They selected a northeastern low wall, named Area 4.1, as the experimental site; the area was mined in two stages. In the first stage, Area 4.1 was excavated from its northern end to the center. A weak-plane interface between an underburden Gray claystone and a thin clay seam, called G1, was daylighted as expected on the pit wall approximately 150 meters each stage without backfilling. The backfill supported the potential sliding block along the weak plane. Therefore, the first stage required a series of sequential excavating and backfilling. The first stage was successfully completed in mid-2013, with the weak plane partially daylighted.
In 2016, the mine planned the second stage – to mine the remainder of the lignite in Area 4.1, this time starting from the southern end. Fig. 1a. shows the beginning of this second stage. Mining began in February 2017, in the middle of the dry season, at the southern end and proceeded along the working face (red line) in a northwesterly direction. Before mining Area 4.1 in the rainy season of 2016, the area was continually monitored for surface and subsurface movements of the undercut slope, the water pressure in the weak plane, and precipitation. The monitoring data unveiled remarkable movements of the undercut slope in response to precipitation; this paper presents some of this key monitoring data. After the lignite was depleted, the backfilling in the area was started and successfully completed at the end of May 2017 before the rains inaugurated. Fig. 1b. shows the location of the undercut low wall and backfilling (yellow shaded area) after mining was completed in Area 4.1.