Africa (Sub-Sahara) Tullow's Cheptuket-1 well in Block 12A of northern Kenya has encountered good oil shows over an almost 2,300‑ft interval, the company reported. The first well to test the Kerio Valley Basin, Cheptuket-1 was drilled to a final depth of 10,114 ft. The results indicate the presence of an active petroleum system with significant oil generation, the company said. Post-well analysis now under way will affect future basin exploration decisions. Tullow is the block operator with a 40% interest. Delonex Energy (40%) and Africa Oil (20%) are the other participants.
Pan, Zhejun (CSIRO Energy) | Heryanto, Deasy (CSIRO Energy) | Down, David (CSIRO Energy) | Connell, Luke (CSIRO Energy) | Camilleri, Michael (CSIRO Energy) | Tan, Yuling (CSIRO Energy) | Sander, Regina (CSIRO Energy)
Cooper Basin is one of the most important onshore oil and gas producing basins in Australia. It also has the most prospective unconventional tight gas and shale gas opportunities. As tight sandstones or gas shales have low permeability, understanding the permeability behaviour is important for the production of these gas resources. In this work, tight sandstone and shale samples were obtained from an exploration well in the Cooper Basin, Australia, and they were cut into cubic samples with about 30 mm on each side using a wire saw. The cubic sample was then placed in a 3D printed membrane, therefore, permeability along each directional axis can be measured. Methane was used to characterise the permeability. Effects of gas pressure and effective stress were studied with gas pressure up to 9.5 MPa and effective stress up to 7.0 MPa. The results shows that the shale has strong permeability anisotropy at different direction. The sandstone sample also showed anisotropic behaviour, but not as significant as the shale. Finally, a reservoir simulator, SIMED II, is used to study the gas production from tight sandstone and shale using hydraulic fractured vertical and horizontal wells. The simulation results show that permeability plays a critical role in the gas production behaviour from tight sandstones and shales.
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.
Nguyen, T. T. T. (Australian School of Petroleum, The University of Adelaide) | Nguyen, L. A. T. (Australian School of Petroleum, The University of Adelaide) | Perdomo, G. E. M. (Australian School of Petroleum, The University of Adelaide)
Explored in 1964 and first oil production launched in late 1984, Mereenie oil and gas field is the largest onshore oil field in mainland Australia. Although the production within the Eastern region has been in decline, an appraisal and development drilling project is expected to extend the life of the field. Therefore, a good understanding of dynamic compartmentalization through validation of material balance modeling would address current production planning and monitoring focused in the current oil production formation, Pacoota 3. This study could be the foundation for future development of the western part of the field.
Over 30 years of production and an enhanced oil recovery scheme which involved periodic injection from abundant gas within the upper formation, Pacoota 1; the producing oil formation has yet had any in-depth study of a dynamic compartment within the production time scale. The main objective of this study is to provide an analytical framework for dynamic compartmentalization. This framework was developed to capture the complexity in completions strategy and in the injection period. In total, six compartments across the Eastern Pacoota 3 formation were successfully identified and confirmed through modeling. However, uncertainties in structure and limited data at the West have contributed to production simulation's shortcomings.
It was found that compartmentalization in Mereenie is a combination of variables; those are a natural baffle, fault sealing, injection rate, and drainage radius; while structural faults have a primary role in decreasing the permeability and mobility of oil, causing discontinuity throughout the formation.
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.
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.
ABSTRACT: The paper presents a numerical modelling approach by discontinuum method to simulate the progressive caving of top coal and roof above a Longwall Top Coal Caving (LTCC) face in Bowen basin, Queensland, Australia. A new caving modelling approach has been developed by the application of strainsoftening material model within UDEC in order to represent the failure and caving induced by the mining process. Results of numerical simulation have improved the understanding on LTCC mechanisms in terms of stress redistribution, rupture mode and failure mechanism in coal and roof strata. These results are in general agreement with site observation and previous longwall studies.
Longwall Top Coal Caving (LTCC) is an improved longwall mining technique that has shown many advantages compared with other methods in terms of coal recovery rate, face equipment design, development cost and spontaneous combustion control for extracting coal seam with thickness in excess of 4.5 m (Hebblewhite et al. 2002). Regarding the geotechnical issues, the applicability of LTCC is believed to highly depend on the cavability of top coal. The presence of top coal as a weak and highly jointed roof rock combined with the higher caving height (Fig. 1) makes the roof caving mechanism different from that caused by conventional longwall mining. Numerical modelling has been widely applied in LTCC studies due to its potential to represent the multiple caving mechanisms under various mining conditions. However, for continuum methods, the models have been limited to implicitly simulating the caving. The discontinuum methods, on the other hand, have mostly used the elastic model for intact rock and thus did not fully represent the failure behavior during caving. This paper aims to improve the understanding of mechanisms associated with caving by developing a discontinuous modelling approach using UDEC strain-softening model (Itasca Consulting Group 2014). The developed model is not only able to explicitly simulate the progressive caving but is also able to incorporate the plastic material response.
Rogers, Clint (Smith Bits a Schlumberger Company) | Jangani, Reza (Smith Bits a Schlumberger Company) | Spedale, Angelo (Smith Bits a Schlumberger Company) | Sadawarte, Sagar (Smith Bits a Schlumberger Company)
The Mereenie development project is targeting oil and evaluating natural gas reservoirs in the lightly drilled Amadeus Basin. In 2012, an operating company started searching for methods to improve rate of penetration (ROP) drilling the 8¾? vertical hole section through the difficult Stairway and Pacoota sandstone formations. The lithology consists of very abrasive and hard siltstone/sandstone with UCS up to over 30,000 psi. The hole section starts at 500 m and generally requires 700 m of total wellbore to reach KOP at 1200 m. The section has historically been drilled with PDC and Roller Cone bits with mud as the circulating medium. Both types of BHAs produced unacceptably slow ROP and required multiple trips to reach TD. The operator required a new approach.
To accomplish the objective, the operator wanted to switch from mud to underbalanced drilling using an air percussion BHA equipped with a hammer bit. However, an analysis using a well records database showed that only short (10–30m) shallow surface intervals had been drilled in Australia with percussion air hammers mostly in mining applications in the 1980–90's.
To increase the chance for early success, the operator wanted to import the latest air hammer tools and drilling techniques from North America. The provider suggested taking lessons learned from the Northeast USA where air hammer drilling plays a major role in developing oil and gas reserves in the region. The two applications are similar with regards to formation characteristics and the drilling team concluded the provider's downhole tool technology, service culture and experience/expertise would be integral to project success. In Q4 2013 the provider drilled the fastest and deepest percussion air hammer run in Australia's Oil and Gas history at 24 m/hr, 700% faster than the previous ROP achieved with PDC or Roller Cone.
Petroleum source rocks occur in most Ordovician sedimentary strata in North America, northern Europe, South Africa, central Australia, and the Baltic area. Many of the source rocks are condensed shales within carbonate-evaporite sequences. Compared with other geologic periods, little oil originates from Ordovician source rocks, but they are important sources for some petroleum systems. Some examples include, 1) the Albion-Scipio field, the only giant field in the Michigan Basin, which contains petroleum generated from Ordovician Trenton-Black River source rocks and 2)the very productive Ordovician Simpson and Ellenburger formations of the west Texas Permian Basin, which aregenerally recognized as sourced from the Ordovician Simpson source rocks. Widespread organic-rich source rocks were deposited during the Late Ordovician Period (Caradocian Stage) as part of an extensive marine transgression before the major glaciation. Upper Ordovician (mostly Caradocian) black shales (e. g. Vinini, Utica/Antes, Trenton, Maquoketa, Sylvan and Simpson, and equivalents) are widespread in North America, as are the Dicellograptus and Clinograptus shales of Northern Europe making many of them potential for unconventional oil exploration.
In recent years, the Utica formation in Ohio has received the majority of industry focus for unconventional oil exploration while many other North American Ordovician formations have gone relatively unexplored. Possible explanations for the limited exploration of the Ordovician Shale are possibly due understanding the maturation levels within the formations. With most of the Ordovician formations appearing in the gas window, these formations are overlooked for exploration in the present hydrocarbon markets. A complete understanding of the maturity levels of the Ordovician aged source rocks needs to be accomplished in order to locate the potential for productive unconventional oil. With a review and understanding of the regional geology, log analyses, geochemical and maturity data of the various Ordovician formations, it is believed that there are many additional areas in North America that have the potential for Ordovician unconventional oil production.