Chullabrahm, Pattarapong (PTT Exploration and Production Public Company Ltd) | Saranyasoontorn, Korn (PTT Exploration and Production Public Company Ltd) | Svasti-xuto, Maythus (PTT Exploration and Production Public Company Ltd) | Trithipchatsakul, Chao (PTT Exploration and Production Public Company Ltd) | Sunderland, Damon (Arup Pty Ltd) | Ingvorsen, Peter (Arup Pty Ltd) | Madrigal, Sarah (Arup Pty Ltd) | McAndrew, Russell (Arup Pty Ltd)
This paper presents an integration of geology, geohazards, geophysics and geotechnical assessments for a design of an offshore gas production facility and an associated export pipeline. The gas field described in this paper is located off the North West coast of Australia in the Timor Sea in a water depth of approximately 130m.
Various resource development options were investigated during the Concept Select / pre-Front End Engineering Design (pre-FEED) phase of the project. These options included fixed and floating structures in the infield area and a 300km long export pipeline that ties into an existing gas trunkline connecting to an onshore processing plant.
To provide the necessary engineering due diligence to allow the project to progress further, several phases of geo-related investigations were undertaken to assess various geohazard challenges and foundation risks. Some of these challenges include a pipeline route traversing several steeply sloping seabed canyons, potential activation of turbidite sequences, and the presence of very soft carbonate sediments to calcarenite rock.
This paper describes these ground related challenges and how they were constrained through the geo-related investigations conducted, observations made and results obtained. Ground related challenges are described in two parts: Pre-FEED export pipeline routing reviews focusing on geohazard, geophysical and geotechnical considerations and ‘real time’ pipeline engineering Finite Element Analysis (FEA) performed offshore. Compared to normal practice, this non-standard offshore analysis allowed a preferred pipeline corridor to be identified during the survey with an informed understanding regarding feasibility and likely seabed intervention, thus optimising the field survey time and cost; and Staged acquisition and integration of infield geophysical and geotechnical data for developing high level assessments of foundation concepts.
Pre-FEED export pipeline routing reviews focusing on geohazard, geophysical and geotechnical considerations and ‘real time’ pipeline engineering Finite Element Analysis (FEA) performed offshore. Compared to normal practice, this non-standard offshore analysis allowed a preferred pipeline corridor to be identified during the survey with an informed understanding regarding feasibility and likely seabed intervention, thus optimising the field survey time and cost; and
Staged acquisition and integration of infield geophysical and geotechnical data for developing high level assessments of foundation concepts.
Key benefits of conducting an integrated approach to geo-related challenges on a complex site will also be presented in this paper.
The selection of completion equipment for artificial lift string for any field in the oil and gas industry is important for the safe and reliable operations of such a field. This is critical to the management and overall profitability of the oil and gas asset, especially in areas where artificial lift is the predominant means of water injection and hydrocarbon production. This paper focuses on why it is important to understand the saline subsurface and the total dissolved solids (TDS) of the environment in which the artificial lift completion is to be deployed and its impact on equipment selection.
High concentration of corrosive components in the well fluid such as hydrogen sulfide, chlorine and total dissolved solids makes the well fluid conducive for electron migration. Such migration causes heavy corrosion, especially when dissimilar metals are used in artificial lift well completions. Carbon steel tubulars and casing are easily affected by such corrosive composition and leads to premature failure of artificial lift completions, which poses safety and operational issues. This type of environment is intense in electrical submersible pump completed wells because of the electromagnetic field generated by the current passing through the electrical cable of the pump system.
A combination of field and laboratory data gathering, and analysis was utilized to determine the effect of the aggressive components of the produced fluid on electrical submersible pumps assembly. The contributions of the high total dissolved solids in the conductivity of the well fluid, and in the electrochemical process for metal corrosion were analyzed. It was evident from both forms and approaches utilized in the analysis that well fluid becomes an electrolyte that provided the desired path for electron flow, which was enhanced by the magnetic field of the ESP system cable.
This paper highlights the integration of three approaches of geochemical analysis of well effluent, Anodic Index differential and tubular internal coating in corrosion prevention and electric submersible pump runlife elongation in wells with corrosive compositions including high total dissolved solids.
Australia is uniquely positioned globally as a major energy provider, but this comes with multiple challenges that must be overcome to realize its full potential. LNG developments that are nearing fruition are set to make Australia the largest supplier of LNG in the world. The Asian LNG market continues to be the growth market. The development of the world's first coal bed methane (coal seam gas) to LNG projects on the east coast has created a robust east coast LNG export market, which in the near future is expected to coincide with domestic energy shortages arising from low exploration activity, maturing fields, higher costs, the interaction of government policy, commercial decisions and activism. As a result, unique approaches to project management and community relations have been developed that are complementary to the Australian consumer's needs for reliable, affordable and cleaner energy. The east coast demand for gas is likely to trigger new development of onshore Northern Territory gas in the short term, if political opposition can be managed. In Western Australia, new approaches leverage technologies such as floating LNG, and more utilization of existing infrastructure and plant capacity to achieve lower costs. This paper outlines Australia's natural gas supply & demand and the challenges to be faced in the coming years.
Xu, Zhaohui (Research Institute of Petroleum Exploration and Development, PetroChina and University of Texas - Austin) | Zhao, Wenzhi (Research Institute of Petroleum Exploration and Development, PetroChina) | Hu, Suyun (Research Institute of Petroleum Exploration and Development, PetroChina) | Zeng, Hongliu (University of Texas - Austin) | Fu, Qilong (University of Texas - Austin)
A mixed siliciclastic-carbonate-evaporite system in the Lower Triassic Jialingjiang (T1j) Formation consists of siliciclastics, limestone, dolostone, anhydrite, and salt, which constitute several petroleum systems. Lateral change of lithology in thin-bedded intervals makes it challenging to predict lithologies by any single seismic attribute in the T1j formation. Principle component analysis (PCA) was applied on tens of seismic attributes to extract lithology information into principle components. The first two components contain most of the lithology information preserved in seismic attributes and were used to correlate with lithology content calculated by core-calibrated wireline logs. Different assembles of end-member lithologies were selected from anhydrite, siliciclastic, tight dolostone, limestone, and salt to perform PCA in different sequences. Distributions of the end members were mixed by color-blending method to map lithology. Basing on the lithology map and regional geology background in the study area, sedimentary facies and their evolution in the T1j Formation were reconstructed.
Presentation Date: Tuesday, September 26, 2017
Start Time: 2:40 PM
Presentation Type: ORAL
In the Northern Territory, the Department of Mines and Energy (DME) is the agency responsible for regulating the exploration and production of oil and gas and the administration of petroleum tenures and petroleum pipelines onshore and in designated coastal waters up to 3 nautical miles seaward from the Territorial Sea Baseline of the Northern Territory. The DME’s role is to ensure that best-practice regulatory principles are applied for the sustainable and safe exploration and production of natural resources in the Northern Territory. In the Northern Territory, hydraulic fracturing has taken place since 1967, mainly as a process to enhance hydrocarbon production from conventional reservoirs with vertical wells. Since 2011, however, hydraulic fracturing has been carried out during exploration for unconventional hydrocarbons. Until now, developmental drilling has taken place only in producing fields in the Amadeus Basin.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 182404, “Unconventional-Resources Exploration and Development in the Northern Territory—Challenges From a Regulator’s Perspective,” by M. Rezazadeh, J. van Hattum, and D. Marozzi, Northern Territory Department of Mines and Energy, prepared for the 2016 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 25–27 October. The paper has not been peer reviewed.
The production of conventional onshore oil and gas in Australia’s Northern Territory began in 1983 from the Palm Valley Field (gas) in the Amadeus Basin. Until 2010, the industry relied on conventional oil and gas development technology, but, in recent years, the focus of the industry has shifted to unconventional-resource exploration. This paper outlines the key issues that must be addressed from a regulatory perspective in regard to the development of an onshore unconventional-gas industry in the Northern Territory.
In the Northern Territory, the Department of Mines and Energy (DME) is the agency responsible for regulating the exploration and production of oil and gas and the administration of petroleum tenures and petroleum pipelines onshore and in designated coastal waters up to 3 nautical miles seaward from the Territorial Sea Baseline of the Northern Territory. The DME’s role is to ensure that best-practice regulatory principles are applied for the sustainable and safe exploration and production of natural resources in the Northern Territory.
In the Northern Territory, hydraulic fracturing has taken place since 1967, mainly as a process to enhance hydrocarbon production from conventional reservoirs with vertical wells. Since 2011, however, hydraulic fracturing has been carried out during exploration for unconventional hydrocarbons. Until now, developmental drilling has taken place only in producing fields in the Amadeus Basin. In the McArthur, Bonaparte, South Georgina, and Pedirka Basins, exploration activities are ongoing.
Onshore Northern Territory oil production comes from the Mereenie and Surprise Fields. Until November 2015, onshore gas production in the Northern Territory came from the Mereenie and Palm Valley Fields. In December 2015, the Dingo Field began producing gas. In 2015, 3,703 MMscf of gas was produced from the three fields.
Current Northern Territory Onshore Petroleum Regulatory Framework
The Northern Territory Petroleum Act is the principal existing legislation regulating oil and gas exploration and production. The DME currently uses the Schedule of Onshore Petroleum Exploration and Production Requirements (referred to here as the Schedule) to regulate petroleum activities; this guideline is similar to that which Western Australia previously used. In 2015, Western Australia replaced the Schedule with its Petroleum Resource Management and Administration Regulations. The Schedule is used to provide requirements to regulate and audit all petroleum activities.
Among major seismic imaging challenges in Vulcan Sub-basin of Timor Sea, Australia, the presence of thick, high-velocity, and faulted Tertiary carbonates in the shallow section overlaid with low acoustic impedance contrast within a soft Cretaceous claystone at the target reservoir makes shallow water multiples the most prominent seismic artifacts in this exploration area. The challenge in this frontier shallow water environment is mainly from inefficient water-layer-related multiples (WLRMs) attenuation. The primary low acoustic impedance at target reflectors are contaminated with short period multiples pose the geological structure uncertainty and incorrect resource and reserve estimation during prospect evaluation process. Unlike conventional demultiple techniques such as Tau-p deconvolution and surface-related multiple elimination (SRME), Shallow Water Demultiple (SWD), developed by CGG, is an efficient tool to attenuate WLRMs in the Vulcan Sub-basin prospect and the result shows significant uplift from the seismic reprocessing project for PTTEPAA.
Rezazadeh, M. (Northern Territory Department of Mines and Energy) | Hattum, J. van (Northern Territory Department of Mines and Energy) | Marozzi, D. (Northern Territory Department of Mines and Energy)
The production of conventional onshore oil and gas in the Northern Territory began in 1983 from the Palm Valley gas field, Amadeus Basin South of Alice Springs. Up until 2010the industry relied on conventional oil and gas development technology albeit with substantial technological advances over time. In recent years the focus of the industry has shifted to unconventional resource exploration, particularly the highly prospective shale gas resources in the McArthur and Georgina Basins. Current estimates indicate that the Northern Territory has more than 200 trillion cubic feet of prospective unconventional natural gas resources in six basins. The technologies and techniques to explore and develop petroleum resources from deep shale are innovations on technologies and practices employed for exploration and development of conventional resources with revolutionary consequences, particularly in North America.
Consoli, C. (Geoscience Australia, now at Global CCS Institute) | Nguyen, V. (Geoscience Australia) | Higgins, K. (Geoscience Australia) | Khider, K. (Geoscience Australia) | Lescinsky, D. (Geoscience Australia) | Morris, R. (Geoscience Australia)
Several offshore sedimentary basins around Australia have been assessed as potentially prospective for CO2 geological storage. A recently completed detailed assessment of one of these basins, the Bonaparte Basin, offshore northern Australia, indicates that the Mesozoic-aged deep saline formations forming the Petrel Sub-basin, a major structure element of the Bonaparte Basin, are highly prospective for CO2 geological storage, and represent suitable depocentres for regional emissions.
Petrophysical, seismic and facies analysis shows that the deep saline formations comprise multiple high quality reservoir-seal pairs. A basin-scale geological model indicates that migration-assisted storage (MAS) is the primary trapping mechanism due to long migration pathways (up to 70 km) with no major structural traps. Plume-scale, dynamic injection simulations show high potential injection rates of over 10 million tonnes supercritical CO2 per annum. After 1000 years, the model predicts maximum plume migration of 30 km from the simulated injection wells. A CO2 storage resource potential of over 15,000 million tonnes was estimated for the reservoirs over the entire Petrel Sub-basin using a methodology suitable for MAS plays.
The highly suitable reservoirs are located less than 300 km from major local CO2 emission sources. This study shows that the Bonaparte Basin in northern Australia is potentially a highly prospective location for carbon capture and storage projects in Australia, and possibly for the broader region.
The Malita Graben, situated within the Bonaparte Basin, is highly under-explored relative to similar geologic settings along the North-West Shelf of Australia. The Mid-Jurassic Elang/Plover Formations have historically been the highly successful exploration target across this basin. However, with high reservoir temperatures and deep formation burial within the Malita Graben, reservoir degradation due to quartz overgrowths was considered a large risk at the Jurassic level. In 2011, D-1 and L-1 wells had drilled at the junction of the Sahul Syncline and Malita Graben to test the Elang/Plover play in the block WA. As a result, thick successions of high-quality Upper-Jurassic to Lower-Cretaceous ‘Sandpiper’ reservoir were intersected. Subsequent seismic, well log synthesis and reservoir characterisation studies have upgraded the potential of Sandpiper sandstones within the Malita Graben, which remain largely under-explored.
The strata penetrated by D-1 and L-1 wells provided key geological evidence to constrain the depositional model associated with the infilling stages of the Malita Graben. The wells intersected thick, homogeneous Late-Tithonian to Early-Berriasian quartzarenite units, encased in pelagic, deep-marine shales. 54m of conventional core was obtained in D-1 well, straddling the Tithonian-Berriasian boundary. The core is considered key as it refines biostratigraphic age dates, gives evidence for turbidite deposition in a deep-basin setting, and reveals a pronounced vertical heterogeneity in permeability readings. Correlating D-1 to L-1 wells suggests coeval stratigraphy, and thus possible lateral connectivity of a sand-rich submarine fan system in the vicinity of Block WA, and possibly in broader regions throughout the Malita depocenter.
The results of D-1 and L-1wells were significant in advancing the understanding of the Sandpiper sand distribution. The occurrence of thick Tithonian and Berriasian sands, which were not expected prior to drilling, opens opportunities for further review of the play in the Malita and Sahul depocenters. However lateral and vertical reservoir heterogeneity of the sands is both complex and challenging to apply to an exploration strategy across the Malita Graben. Modern seismic data may help enhance the understanding of the Sandpiper play in the area, but predicting clay mineralogy and its association with diagenetic processes on individual lobe sequences may remain elusive.
The Malita Graben is a prominent depocentre within the Northern Bonaparte Basin and contains up to 10km of Mesozoic to Cenozoic sediments. Previous exploration in the area has been focused on the Middle Jurassic Elang-Plover play, but drilling has been largely restricted to structural highs adjacent to the main depocentres. Limited drilling has been undertaken within the Malita Graben, primarily because of reservoir quality risk sassociated with deeply buried, high temperature reservoirs.