Copyright 2019 held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors. ABSTRACT Today, many machine learning techniques are regularly employed in petrophysical modelling such as cluster analysis, neural networks, fuzzy logic, self-organising maps, genetic algorithm, principal component analysis etc. While each of these methods has its strengths and weaknesses, one of the challenges to most of the existing techniques is how to best handle the variety of dynamic ranges present in petrophysical input data. Mixing input data with logarithmic variation (such as resistivity) and linear variation (such as gamma ray) while effectively balancing the weight of each variable can be particularly difficult to manage. DTA is conceived based on extensive research conducted in the field of CFD (Computational Fluid Dynamics). This paper is focused on the application of DTA to petrophysics and its fundamental distinction from various other statistical methods adopted in the industry. Case studies are shown, predicting porosity and permeability for a variety of scenarios using the DTA method and other techniques. The results from the various methods are compared, and the robustness of DTA is illustrated. The example datasets are drawn from public databases within the Norwegian and Dutch sectors of the North Sea, and Western Australia, some of which have a rich set of input data including logs, core, and reservoir characterisation from which to build a model, while others have relatively sparse data available allowing for an analysis of the effectiveness of the method when both rich and poor training data are available. The paper concludes with recommendations on the best way to use DTA in real-time to predict porosity and permeability. INTRODUCTION The seismic shift in the data analytics landscape after the Macondo disaster has produced intensive focus on the accuracy and precision of prediction of pore pressure and petrophysical parameters.
Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%),
Africa (Sub-Sahara) Sahara Group discovered hydrocarbons in three wells drilled in Block OPL 274, located onshore in Nigeria's Edo State. Olugei-1 was drilled to a measured depth of 4537 m and encountered five hydrocarbon zones, with 33 m of net pay. Oki-Oziengbe South 4 was drilled to a measured depth of 3816 m and encountered 64.3 m of net pay in 13 hydrocarbon-bearing zones. Oki-Oziengbe South 5 was drilled to a measured depth of 3923 m and encountered 91 m of net pay in 19 reservoirs. Sahara Group (100%) is the operator. Asia Pacific Sino Gas & Energy Holdings (SGE) flowed gas (coalbed methane) from its first horizontal well in the Linxing production sharing contract (PSC) in China's Shanxi province.
Santos discovered gas condensate at its Lasseter-1 exploration well in block WA-274-P, located in the Browse basin, offshore Western Australia. The well reached a total depth of 5329 m and was drilled in 404 m of water. Wireline logging has confirmed 78 m of net pay over the Jurassic-aged Lower Vulcan and Plover intervals, between 4880 and 5285 m measured depth. Multiple independent hydrocarbon columns have been detected, including an estimated 250-m column for the Lower Vulcan reservoirs. Santos (30%) is the operator, with Chevron (50%) and Inpex (20%).
Africa (Sub-Sahara) Eni Congo discovered oil at its Minsala Marine 1 well offshore the Republic of the Congo in Marine XII Block 12 km from the operator's recent Nené Marine discovery. Minsala intersected 420 m of gross pay and encountered light oil in a Lower Cretaceous presalt sequence. The well reached a total depth of 3700 m. Eni (65%) is operator, with state-owned partner SNPC 25%), and New Age (African Global Energy) Limited (10%). SOCO EPC's Lindongo X Marine 101 Well (LXM-101)--located offshore the Republic of Congo in Marine XI Block--encountered oil in a clastic sequence of the Djeno sands, with early log interpretation indicating approximately 50 m of gross pay.
A development programme offshore Western Australia required near horizontal 8.1/2" wellbores to be drilled through challenging formations. The hole section intersected sand-shale interlayers, referred to as the Tiger Sands, which is an abrasive formation with unconfined compressive strength (UCS)between 15,000psi and 20,000psi, with maximum UCS recorded up to 30,000psi. Underlying the Tiger Sands is the well cemented, abrasive Brewster sandstone with average UCS of 15,000psi and maximum UCS recorded up to 21,000psi, which has demonstrated a propensity to natural fractures. These challenges resulted in poor bit durability, low rate of penetration (ROP), difficult directional control,excessive shocks and downhole vibrations and significant downhole mud losses. The complexity of the drilling conditions required a systematic approach to be employed to optimise the poly-diamond crystalline (PDC) drill bit solution in order to improve durability and optimise ROP while successfully managing directional control, losses and ultimate drilling cost through the interval.
In addition to drill log analysis, after operations reviews (AORs) provided a comprehensive summary of operations from a rig perspective. These summaries were then used by the onshore engineering team to work in collaboration with the service sompany engineering team to develop a bit optimisation strategy. The first development well of the campaign was drilled with a standard 8 bladed 13mm PDC bit.
Natural fractures were penetrated and a total of ~4,500bbl of synthetic sased sud (SBM) was lost to the formation. The bit suffered impact damage and, therefore, had reduced durability. To solve thisproblem, a systematic approach was followed to gradually introduce improved design elements. Bit design progressed from cutter design, improved technology and ultimately, the introduction of new PDC cutter technology to record the fastest on bottom ROP for the drilling campaign of 10.32m/hr. Improved ROP and optimisation of the loss treatment strategy, allowed drilling operations to continue with minimal exposure to losses when present. Positive AOR feedback and continuous development from the service company resulted in further improvements to the PDC bit design with the introduction of ridged diamond elements and the latest generation conical elements to further improve steerability and ROP.
Continued developments resulted in New Design 4 being run in well 10. The entire interval was drilled in one run with excellent steerability and an overall 159% improvement in ROP equating to a reduction in drilling time by 5 days going from the original 813 PDC to the final New Design 4. In addition to ROP improvements, losses did not prove prohibitive to reaching TD due to drilling efficiency. Subsequent further improvements in ROP have been realized, with the entire interval drilled at 16m/hr.
Drilling procedures, drilling fluids program, cementing program, drilling hazards—These are some of the most common considerations for a drilling engineer when designing a drilling program. As boreholes have gotten deeper and lithologies harder and more complex, however, controlling the costs of these operations has become increasingly challenging. The often-sidelined drilling optimization process plays a vital role in helping companies minimize the cost of complex operations and mitigating certain risks that cannot be overlooked. At its core, drilling optimization is about drilling in the most efficient way possible; to meet all drilling objectives while minimizing overall drilling costs. With rig rates running upwards of a million dollars a day for some operations, shaving even a few minutes off the drilling time can result in tens of thousands of dollars in savings.
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.