Carbonate reservoirs are commonly heterogeneous and their reservoir quality results from complex interactions between depositional facies and diagenetic processes. The Diagenetic Diagram is a powerful tool that helps in the characterization of the diagenetic processes that have affected the reservoir. From this knowledge, it is possible to significantly improve the understanding of the reservoir's pore system and permeability distributions, which are key factors for development optimization and production sustainability.
A multi-scale and multi-method study (petrography, blue-dye impregnation, selective staining and porosity determination) of Middle Jurassic carbonates from the Lusitanian Basin (Portugal) has been undertaken, to find the best systematic approach to these reservoirs. It has involved thorough diagenetic characterization of each lithotype (lithofacies, texture, porosity, qualitative permeability assessment and diagenetic evolution). The study area was selected based on its excellent and varied exposures of carbonate facies and availability of core.
Methodological and terminological challenges were faced during the study, especially dealing with data coming from several scales (macro, meso, and micro). In order to overcome these challenges, a diagenetic diagram was developed and applied to the selected rocks. It is a tool that allows the integration of data coming from outcrops, hand samples, cores, cuttings, thin sections, and laboratory experiments.
This is carried out in a dynamic, guided, systematic, and rigorous way, enabling the evaluation of the relationship between facies, diagenetic evolution and pore systems. The latter are characterized regarding size, geometry, distribution, and connectivity. This enables the identification and characterization of permeability heterogeneities in the rocks. It was concluded that the main porosity class (i.e. secondary) was created by diagenetic processes.
The proposed method has strong application potential for: detailed characterization and understanding of porosity and permeability in carbonate reservoirs, from a diagenetic evolution and fluid flow perspective (e.g. SCAL and pore system description); definition of diagenetic trends for modeling petrophysical properties and rock types. In this regard, the method is being applied to a Valanginian carbonate reservoir in Kazakhstan, and some preliminary results are presented in this paper. Refining this technique may be helpful for similar carbonate studies, enhancing the results of typical diagenetic studies by improving the characterization of reservoir properties at various scales, thus contributing to a more sustainable exploitation of hydrocarbon reservoirs.
The amount of tight formations petrophysical work conducted at present in horizontal wells and the examples available in the literature are limited to only those wells that have complete data sets. This is very important. But the reality is that in the vast majority of horizontal wells the data required for detailed analyses are quite scarce.
To try to alleviate this problem, a new method is presented for complete petrophysical evaluation based on information that can be extracted from drill cuttings in the absence of well logs. The cuttings data include porosity and permeability. The gamma ray (GR) and any other logs, if available, can help support the interpretation. However, the methodology is built strictly on data extracted from cuttings and can be used for horizontal, slanted and vertical wells. The method is illustrated with the use of a tight gas formation in the Deep Basin of the Western Canada Sedimentary Basin (WCSB). However, it also has direct application in the case of liquids.
The method is shown to be a powerful petrophysical tool as it allows quantitative evaluation of water saturation, pore throat aperture, capillary pressure, flow units, porosity (or cementation) exponent m, true formation resistivity, distance to a water table (if present), and to distinguish the contributions from viscous and diffusion-like flow in tight gas formations. The method further allows the construction of Pickett plots without previous availability of well logs. The method assumes the existence of intervals at irreducible water saturation, which is the case of many tight formations currently under exploitation.
It is concluded that drill cuttings are a powerful direct source of information that allows complete and practical evaluation of tight reservoirs where well logs are scarce. The uniqueness and practicality of this quantitative procedure is that it starts from only laboratory analysis of drill cuttings, something that has not been done in the past.
Healy, John C. (John C. Healy Jr Consulting LLC) | Sanford, John R. (ENI International Resources Ltd) | Reeves, Donald Franklin (Noble Energy Inc.) | Dufrene, Kerby John (Schlumberger) | Luyster, Mark R. (M-I Swaco) | Offenbacher, Matthew A. (MI-SWACO) | Ezeigbo, Chinyereze (M-I Swaco)
A case history from Offshore Israel is presented that describes the successful delivery of two ultra high-rate gas wells (>200 MMscf/D) completed in a depleted gas reservoir with 9??-in. production tubing and an openhole gravel pack (OHGP). Maximizing gas off-take rates from a volumetric drive gas reservoir that possesses high flow capacity (kh) requires large internal diameter (ID) tubing coupled with efficient sand face completions. When sand control is required, the OHGP offers the most efficient as well as the most reliable, long-term track record of performance. A global study of wells completed with 9??-in. production tubing ("big bore??) determined that this design concept was feasible and deliverable in a short time frame while still maintaining engineering rigor. The paper will highlight key accomplishments within various phases of a completion delivery process with particular emphasis on the sand control design, testing and execution. The completions were installed with minimal issues (NPT ˜ 9%) and have produced without incident. The two wells, Mari-B #9 and #10, achieved a peak gas rate of 223 and 246 MMscf/D, respectively.
Demand for natural gas is increasing more rapidly than anticipated in Far East markets because (1) China has modified its policies in order to increase reliance on gas, in part to mitigate the growth in its coal consumption (which now stand at almost half of world coal production), (2) Japan has announced its intention to eventually shutdown its nuclear power industry, and (3) India, which currently has more than 400 million people without electricity, desires to accelerate electrification. This analysis investigates the potential role of stranded gas from Central Asia, Russia, Southeast Asia, and Australia in meeting Asia's future demand for gas imports. It initially surveys the discovered or known gas in stranded gas accumulations in Central Asia, Russia, Australia, Indonesia, and Malaysia. It then examines the primary gas import markets of China, India, Japan, and South Korea by describing energy use, gas demand trends, and domestic gas supplies to establish boundaries that encompass the wide variation in gas import demands in these markets during the two decades following 2020.
Then the cost of developing and delivering gas through overland pipelines from selected stranded gas fields in Central Asia and Russia to China is examined. Analysis shows that for the Shanghai market in China, the costs of developing and delivering Russia's stranded gas from the petroleum provinces of eastern Siberia are competitive with costs estimated for stranded gas from Central Asia. However, for the Western Siberian Basin, delivered gas costs are at least 3 US dollars per thousand cubic feet (USD/Mcf) higher than delivered gas from Central Asia.
The extraction and transport costs to a liquefaction plant for gas from stranded gas fields located in Australia, Indonesia, Malaysia, and the basins of eastern Siberia are then evaluated. The resource cost functions presented show development and extraction costs as a function of the volume of stranded gas developed for each country. The analysis demonstrates that, although the Russian fields in areas of eastern Siberia are large with relatively low extraction costs, distances to a potential liquefaction plant at Vladivostok make them initially the high cost suppliers of the liquefied natural gas (LNG) market. For the LNG markets examined, Australia and Malaysia are initially the lowest cost suppliers. For the Shanghai market, a comparison of the cost of supplying gas by pipeline with the cost of supplying LNG shows that the pipeline costs from areas of eastern Siberia and Central Asia are generally lower than delivered cost of gas as LNG from the LNG supply sources considered.
Qiao, Dongsheng (Center for Deepwater Engineering, Dalian University of Technology) | Ou, Jinping (Center for Deepwater Engineering, Dalian University of Technology) | Wu, Fei (Luxun Academy of Fine Arts)
Shale gas exploration activities have been growing rapidly in Australia. A flow rate of up to 2 MMSCFD has been reported recently from the first exploratory vertical well in the Cooper Basin in South Australia. Perth and Canning Basins in Western Australia are also reported to be highly prospective. However, shale gas production differs from conventional reservoirs primarily because of extremely low permeability and other petrophysical characteristics. Commercial production requires massive hydraulic fracturing often in long horizontal completions.
The potential development of a shale gas field in Western Australia has been simulated to optimize production and minimize development cost through sensitivity analyses. Conditions in Australia are particularly challenging often because of significantly higher costs in drilling, completion and fracturing than those of the US. The minimum number of wells and the maximum Net Present Value (NPV) was iterated by simulation. The factors influencing their overall success of the field
development project were investigated in order to generate a workflow model suitable for a variety of cases. The influence of well fracture and other parameters such as completion length, fracture geometry, permeability and gas price was tested against NPV to optimize the development. Optimization of any development should be possible by iterating on any parameter and the related variables. Whilst in conventional gas there is a clear understanding of what is economically viable, this is not the case in shale gas particularly in Australia. Before embarking on any drilling, testing or development activities simulation sensitivity studies of this nature are essential.