Offshore Thailand Research Articles

Technology Focus: Drilling Innovation (February 2019)

Technology Focus From the beginning, the name of the game has been innovation. No single word has characterized drilling design and operations more completely during the 160 years since Colonel Drake first probed the Pennsylvania landscape for oil. This fundamental aspect of our business applies now more than ever across geographical and corporate boundaries. Examples of evolution in well construction during the past several years include new horizontal-well applications, breakthroughs in bit and directional-drilling technology, synthetic fluids, fracture-stimulation advancements, managed-pressure drilling, and the digital revolution. All this being said, few could have imagined the present state of the industry unfolding with the development of unconventional resources. During the past 7 years alone, US oil production has again become a dominant global force, doubling from 5.5 million to more than 11 million B/D. Even greater effects on gas reserves have been realized with the expansion of infrastructure to deliver a rising tide of new gas production to consumers. Around the globe, the ultimate benefits of these current trends remain to be seen as new reserves continue to be identified within most of the world’s oil- and gas-producing regions. Papers selected for this feature serve as superb examples of drilling evolution in a variety of locations, including US onshore, offshore Thailand, deepwater Gulf of Mexico, Sakhalin Island, and the North Sea. In each case, evolution in well design, equipment, and operational procedures has occurred, resulting in dramatic advancements in technical feasibility, efficiency, and safety. Paper SPE 191783, “Drilling Extended Laterals in the Marcellus Shale,” reveals advancements underpinning new unconventional production in that area as well as in the Permian Basin, the Bakken, the Eagle Ford, and the Utica fields. Successful results published by international and offshore operators in Papers SPE 191054 and OTC 29065 highlight not simply new tools or procedures but also far-reaching breakthroughs that fundamentally alter the outlook and value of these types of assets. Papers referenced in the pages that follow offer but a glimpse into a greater library and wealth of knowledge available to SPE readers desiring to remain connected with drilling innovations. Recommended additional reading at OnePetro: www.onepetro.org. SPE 191090 Simultaneously Drilling and Underreaming Directional Topholes With Underreamer Below Mud Motor Saves a Trip in Collision-Free Operations: Offshore Sakhalin Island Case Study by Ruslan Kasumov, Schlumberger, et al. IADC/SPE 191099 Complete Managed-Pressure-Drilling Rigs: Is This the Future? by Ben Gedge, PVD Well Service, et al. SPE 191331 Drilling a Challenging Kvitebjørn Field 53/4-in. Section in a Single Run Using a New Mud-Motor-Modeling Engineering Work Flow and New Long-Life Elastomer by Hany Ahmed Beeh, Schlumberger, et al. SPE 191338 Out-of-Zone Injection by A. Galiev, PJSC Tatneft, et al.

Debottlenecking Through Produced-Water Partial Processing Unlocks Production

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 187109, “Partial Processing: Produced-Water Debottlenecking Unlocks Production on Offshore Thailand MOPU Platform,” by C.H. Rawlins, SPE, eProcess Technologies, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 9–11 October. The paper has not been peer reviewed. An operator in the western Gulf of Thailand installed two water-management partial-processing systems on its mobile offshore production units (MOPUs) to increase oil production. Water removed at the production manifold is treated and transferred directly to the injection system, thus bypassing primary separation, transfer piping, fluid heating, and floating storage facilities. Water debottlenecking increased oil production by 80% and reduced the in-field transfer volume by 62%. Introduction In mature oil basins, the ability to sustain oil production depends on managing an increasing volume of produced water. The partial-processing method seeks bulk (not complete) removal of a throughput-constraining phase from oil and gas production using compact processing equipment. Partial-processing technology normally is installed on facilities that have space or weight constraints, where traditional separation technologies will not fit. Fitting within or around existing process equipment, partial-processing equipment maximizes the capability of an existing facility footprint. The constraining phase may be gas or water, and specific technologies are available to address each. The application detailed in this paper addresses produced-water debottlenecking. Removal of the water constraint unlocks production potential from mature or marginal fields and has been shown to increase hydrocarbon production. Design Stages and Setup For water-constrained systems, the most significant benefit comes from the removal of bulk water as far upstream as possible. High-water-cut wells are combined into a discrete manifold that may handle part or all of the field production. The partial-processing system is on this manifold, upstream from the existing process equipment. Debottlenecking at this point opens capacity in the flow lines, transfer piping, and processing facilities. The partial-processing skid can be installed on unmanned platforms with limited utilities and space and weight constraints. Bulk water removal and treatment may have two or three stages. The first stage, preseparation, involves bulk water removal from the multiphase-flow stream. A specially designed liquid/liquid hydrocyclone (preseparator) removes a bulk portion (60–95%) of the water from the flow stream. Next, the removed bulk water passes to the deoiler hydrocyclone, which operates in a standard produced-water-treating mode. For example, the preseparator will reduce oil content from 10 to 0.2%. The deoiler will take the 2,000-ppm oil down to or near discharge quality (20–50 ppm), depending on oil properties, pressure drop, and temperature. A tertiary treatment stage is optional and is used for difficult separation (e.g., cold fluids with heavy oil) or very stringent disposal requirements (e.g., low oil-in-water levels for enhanced-oil- recovery injection). This stage uses a compact flotation unit (CFU) for both degassing and oil polishing. The CFU removes gas effervescing from solution after the deoiler (which can be 5–10% of the gas void fraction) and uses that gas to float the fine oil droplets.

Present-day stress orientation in Thailand's basins

The Cenozoic tectonic evolution of Thailand is widely considered to have been primarily controlled by forces generated at the eastern Himalayan syntaxis. This hypothesis is supported by earthquakes in northern Indochina and southern China, which reveal a fan-shaped present-day maximum horizontal stress ( S Hmax) pattern centered on the eastern Himalayan syntaxis. However, the distance to which forces generated by the Himalayan syntaxis influence the stress pattern in Indochina is not known. We analyzed caliper and image logs from 106 petroleum wells for borehole breakouts and drilling-induced fractures. A total of 558 breakouts and 45 drilling-induced fractures were interpreted in six basins, indicating that a north–south regional present-day S Hmax exists in central and southern Thailand and the Gulf of Thailand. The N–S S Hmax orientation suggests that forces generated at the Himalayan syntaxis are a major control on the stress pattern throughout Thailand, extending approximately 1000 km beyond the outer limit of syntaxis-associated seismicity. Despite the influence of the Himalayan syntaxis on the present-day stress field, the sedimentary basins of central, southern and offshore Thailand are characterized by structural styles that are somewhat inconsistent with those predicted to result from India–Eurasia collision. Furthermore, localized variations in S Hmax orientation, and the predominance of structures associated with purely extensional rifting, indicate that other processes also influence the stress field in Thailand. We suggest that stresses generated by the Sumatran–Andaman subduction zone may also have resulted in significant deformation in offshore Thailand and that the stress pattern may also be perturbed at very local (several km) scales by mechanically weak faults.

High-resolution 3D seismic imaging in practice

Pearl Oil (Thailand) acquired a high-density, high-resolution 3D seismic survey in 2004 to establish an accurate geologic framework for development drilling of the Jasmine oil field in block B5/27, offshore Thailand (Figure 1).

Techbits (January 2005)

The SPE Applied Technology Workshop on “High-CO2 Gasfield Development and Production” held in Hanoi, Vietnam, in September 2004 was attended by 79 participants from 11 countries. The keynote address, given by Joe Gregory, Gorgon Development Manager for ChevronTexaco Australia, highlighted the challenges of the Gorgon CO2 field, discovered 20 years ago. The technical agenda included Characteristics of High-CO2 Gas Fields; Development, Production, and Monitoring Strategies; Surface Facilities and Removal Techniques; High-CO2 Pipelines and Disposal/Usage of Removed CO2; End-User Requirements; and Business Drivers. Emphasizing the importance of finding solutions to commercialization of high-CO2 gas fields in Vietnam and other countries, Nguyen Dang Lieu, Vice President of PetroVietnam, gave the opening address, and Lawrence Duhon of Unocal Thailand concluded the opening session by outlining participants’ expectations for the workshop. Two breakout workshop sessions, a poster session, and general discussion completed the workshop. The 21-member Program Committee included Cochairpersons Nguyen Van Minh of PetroVietnam, Lawrence Duhon of Unocal Thailand, and Kanit Sangwongwanich of PTTEP. Committee members included Ahmad Hanif of Pertamina, Kemal Anbarci of ChevronTexaco Australia, Dale Coleman of ExxonMobil E&P Malaysia, Jeffrey Harris of Unocal Vietnam, He Jiangchuan of PetroChina, Huynh (Anthony) Bui of Chevron Offshore Thailand, Khairul Nizam Zaini of Petronas Carigali, Teddy Komaroedin of ConocoPhillips Indonesia, Christopher Lenn of Schlumberger UAE, Kamel Bennaceur of Schlumberger U.K., Nguyen Quynh Lam of Truong Son Joint Operating Co., Lincoln Patterson of CSIRO Petroleum, Phan Trung Nghia of PetroVietnam, Erik Puik of Shell Global Solutions, Hemanta Sarma of the U. of Adelaide, Suhardiman of Pertamina, Tam Thiam Guan of Shell E&P Intl., and Djebbar Tiab of the U. of Oklahoma. Highlights captured during the workshop are summarized by session.

The Influence of Internal Waves on Deep-Water Drilling

Internal waves were observed during drilling by the drillship Discoverer 534 in the Andaman Sea, offshore Thailand, in water depths ranging from 1,900ft to more than 3,400ft. An engineering analysis was conducted on measured internal wave data and simultaneous measured drillship response. Knowledge of internal waves will be required for designing production facilities in deep water. Introduction This paper describes a new environmental loading factor that may influence future deep-water operations internal waves. Our experience has verified that internal waves are present in the Andaman Sea, and the literature indicates that internal waves exist in all oceans. The Discoverer 534, under contract to Esso Exploration Inc., operated successfully in the Andaman Sea in water depths ranging from 1,900 ft to more than 3,400 ft. While internal waves were present during much of the operating period, they had no significant impact on drillship period, they had no significant impact on drillship operations. However, because internal waves of magnitude greater than those observed by the Discoverer 534 are possible, Exxon Production Research Co. began a possible, Exxon Production Research Co. began a measuring and modeling program to obtain a detailed engineering description of internal waves. The measuring program, conducted during Oct. 1976, was designed to program, conducted during Oct. 1976, was designed to measure simultaneously internal waves and the corresponding drillship response. A subsequent internal wave-modeling effort now is under way. In the next sections, we briefly review the properties of internal waves, discuss the measurements of internal waves in the Andaman Sea, and describe typical drillship response to moderately sized internal waves. Characteristics of Internal Waves Background Internal waves are water waves that propagate beneath the ocean's surface. Just as surface waves propagate along the boundary layer formed between the ocean and the atmosphere, internal waves propagate along the boundary layer between water of greater and lesser density. Such boundary layers are associated with the oceanic thermocline and normally are characterized by warm, less-saline water lying over cold, more-saline water. Internal waves may exist in any body of water stratified by temperature and/or mineral content. However, energy sources must be available to generate the waves. For example, current flow over uneven bathymetry, shear current flow, and atmospheric disturbances may cause internal waves to form. Internal waves may have a finite amplitude everywhere in the water column except at the bottom, where it is zero. The internal wave amplitude on the ocean's surface is usually small, preventing easy surface observation. The maximum amplitude normally is found near the average depth of the main thermocline. Internal waves commonly are found everywhere in the world and range in size from small-scale microstructures to waves with measured amplitudes as great as 180 m. However, these waves cannot have amplitudes greater than the average thermocline depth and, just as surface waves, they are limited in height by water depth. Normally, internal waves in shallow water are moderately sized, only a few meters or tens of meters high, being limited primarily by available energy sources, thermocline depth, and water depth. JPT P. 1497

Petroleum Developments in Far East in 1977

Petroleum activity in the Far East during 1977 witnessed a slight recession compared to 1976. Peninsular Malaysia, India, and the Philippines registered significant gains. Areas which declined significantly were Bangladesh, Burma, and Thailand. Indonesia, which encompasses about 25% of the total activity showed a 12% decline. Approximately 426 exploratory wells were reported in the region compared to 504 in 1976. Again, as in 1976, 27% of these were drilled in Indonesia. Exploratory wells drilled in 1977 resulted in discovery of 32 oil fields and 17 gas fields. This total excludes the People's Republic of China, Afghanistan, India, onshore Bangladesh, and Burma, because they do not release official results of onshore drilling. Production during 1977 rose to approximately 4,062,600 BOPD, a 6.6% increase. India, Indonesia, and the People's Republic of China all registered sizable gains to account for most of the increase. The most significant discoveries, although they do not represent large quantities of hydrocarbons, were in the Philippines and Thailand. These discoveries appear to have added the quantity necessary to allow these countries to become commercial producers of hydrocarbons for the first time. The People's Republic of China also apparently had a major discovery in the East China Sea, north of Hainan Island, but no details are known. During 1977 there was a general pull-back by foreign contractors into the more established petroleum provinces. The exception was in Vietnam where contract negotiations continued by several companies. Acreage blocks were awarded to AGIP, Deminex, and Elf-Aquitaine. Also in the Philippines, owing to the implementation of seismic option contracts, large areas were taken. These areas are subject to further negotiations if companies wish to extend their option to drill. On the negative side, major relinquishments occurred in Bangladesh, Burma, Maldive Islands, Sri Lanka, the Andaman Sea in offshore Thailand, and South Korea. These areas apparently showed little exploration encouragement to foreign contractors. It is interesting to note there are no foreign contractors represented in Burma and South Korea, 2 of the active new areas in 1976.