The uncertainties of overpressure estimation are among the major challenges to the development of deep and hot reservoirs in many sedimentary basins especially with regards to drilling safety and well economics. However, because of the anticipated huge economic benefits of HPHT geological environments, stakeholders in the oil and gas industry consistently seek to have a good understanding of subsurface pressure systems in order to promote safe and sustainable investments therein. Accordingly, information is required to improve the regional knowledge of geopressures and for the calibration of functions aimed at optimising pre-drill pore pressure estimates for future wells. The Central North Sea, with its vast number of HPHT wells, pressure data, drilling information and documented operational experiences in exploration, drilling, development and production activities stands in a good stead as a "geopressure laboratory" for the fine-tuning of pore pressure prediction concepts, improvement of current geopressure practices and ultimately guide investment and operational decisions in the unexplored areas of the basin itself and elsewhere as geological realities could permit. For this reason, this study utilised downhole pressure-related data and wireline logs to evaluate the pressure regimes in the Central North Sea. The approach involved the quantification of overpressures using standard pore pressure prediction methods that make use of the density and velocity logs of mudstones. The results show that the estimated pore pressure profiles are consistent with measured pressure data in the Cenozoic formations, which makes it reasonable to assume that disequilibrium compaction is the cause of overpressure in this shallow section of the wells. Going deeper into the wells, within the sub-Chalk section, typical calibration parameters from log data could not be used to achieve reliable estimates of overpressures as was the case in the Cenozoic section. Remarkably, while it is possible to adjust the Eaton exponents in order to match estimates with measured data, a wide range of exponent values of between 4.0 and 7.0 is however required. The implication is that there is no systematic variation of the Eaton exponents with the amount of overpressure or depth of burial of the sub-Chalk strata.
Accessing and producing the Gulf of Mexico's Lower Tertiary and other ultradeepwater plays require aggressive reservoir stimulation and a downhole infrastructure capable of supporting decades of high production rates in extreme environments. The Baker Hughes Hammerhead system is the industry's first wellhead-to-reservoir integrated completion and production solution specifically designed and tested for ultradeepwater conditions. Built to withstand pressures and temperatures up to 22,500 psi and 300 F, the system is capable of handling sustained flow rates up to 30,000 B/D with high differential pressures up to 15,000 psi for maximum reservoir drainage. With the integrated system, operators will be able to reliably access Lower Tertiary reservoirs and maintain long-term production, safely and reliably, for full-field economic payback.
Field Trips Each field trip below is free of charge and can accommodate up to 20 participants on a first-come, first-served basis. To find out more, or to register your interest, please contact Julie Atkinson. FIELD TRIP 1 12 November, Tectono-Stratigraphic Sequences and Semail Ophiolite Emplacement Relationships, Jebel Fayah Range, Sharjah, UAE Jebel Fayah is a N-S oriented frontal foreland fold to the Oman mountain belt, located in central UAE.
Characterization of a carbonate reservoir is often difficult due to the complexity of its pore system. This study presents an integrated approach using well-log and microgeological data to characterize rock fabrics and their pore system for a carbonate reservoir in the Ham Rong (HR) structure, offshore the Red River basin, Northern Vietnam. Based on such well-log data as gamma ray (GR), photoelectric factor (PEF), neutron porosity (PHIN), and bulk density (RHOB), two major rock types of dolostone and limestone were identified. A further combination using the results of thin-section and scanning electron microscope (SEM) analysis indicated four types of carbonate rock fabric, and namely, limestone with grain-dominated grainstone, limestone with grain-dominated packstone, dolostone with grain-dominated grainstone and dolostone with grain-dominated packstone. For each identified carbonate fabric, two types of pores were found, including interparticle and vuggy pores. The latter can be further subdivided into separate-vug pores and touching-vug pores. For the HR structure, the touching-vug porosity and the interparticle porosity were estimated to be in the range of 1 to 3% and 1 to 8%, respectively. The intercrystalline porosity, which might be considered as a subset of the interparticle porosity and could be estimated by SEM analysis, was found in the range of 1.5 to 3%. It is expected that the integrated analysis approach using well-log and microgeological data employed in this study can be applied to evaluate the characteristics of carbonate reservoirs at other wellsites in the Red River basin. It worth noting that the fracture porosity calculated based on thin-section analysis matched quite well with the porosity calculated by resistivity log data and using 2D and 3D fracture models.
Montaron (2008) reported that more than 60% of oil remaining is contained in carbonate reservoirs in the world and 40% of its gas reserves is held in carbonate fields. Southeast Asia, in general, and Vietnam, in particular, are located in the humid tropical zone with a warm climate which provides suitable conditions to develop the coral platform, which in combination with tectonic activities, could form carbonate reservoirs. In reality, carbonate rocks are found in many locations in Vietnam, where carbonate rocks can be grouped in four age groups from Precambrian to Permian-Triassic periods, as shown in Fig. 1.
According to EIA (
The complete evaluation methodology has 4 phases: 1) petrophysical evaluation, that includes multimineral evaluation, porosity estimation and calibration with mineralogical analysis; 2) TOC content evaluation, that includes TOC content estimation, using 3 methods: density logs
La Luna Formation and La Grita Member of Capacho Formation are mainly composed by carbonatic rocks, with high content of calcite (above 75%) and low content of clay minerals. In both units, the estimation of TOC content varies from 0.50 to 9%. Mechanical properties show moderate values of Poisson's ratio (0.20 to 0.32), high values of Young's modulus (0.80 to 9.60x 106 psi) and UCS (6.20 to 31.00x 106 psi). In the Cretaceous sequence, the state of stress changes according to geographic location in the basin, from normal in northwest region and central lake region, to transcurrent and reverse in southeast region. The brittleness index estimated for different methods varies from 0.54 to 0.85, which indicate that both units may be classify as brittle.
The integration of geomechanical and petrophysical analysis allowed identifying prospective intervals in both units, with thickness between 20 to 100 ft. Therefore, the study indicates that both units show very good conditions for horizontal drilling and hydraulic fracturing. Moreover, the comparison of various estimation methods of TOC content and brittleness index allowed to observe the uncertainty presented by these parameters in analysis of shale plays.
The Auca Mahuida Volcano and Las Manadas field produces oil and gas from the Mulichinco, Lower Centenario and Rayoso formations. However this high quality reservoir has been severely damaged due to volcanic activity.
This volcanism occurred after the main hydrocarbon migration and trapping, although there are hydraulically isolated bodies related to the igneous intrusions, confirmed from pressure testing and the distribution of the fluid along the stratigraphy column. The attitude and distribution of these intrusions in the reservoir is not generally known in part due to the lack of the surface seismic over this geologically complicated area.
The big challenge is to be able to accurately identify and rank the intrusive igneous features such as dykes, sills, laccolith and other geological features.
A new borehole image was introduced in Argentina for oil based mud systems. It has very good coverage with 80% in 8 inch wells. It is composed of 6 pads mounted in 6 independent articulated arms, each pad has 10 sensors resulting 60 micro-resistivity measurements. This tool works on different frequencies for different formation resistivity range. Depending on the known resistivity two frequencies can be simultaneously selected to acquire two images in one single pass. Recommended logging speed is 5.5 m/min.
As a result of the operations more than 2000 meters have been logged with high quality borehole imaging. In spite of hostile weather conditions and because it is a natural protected area, there were no incidents registered during these jobs.
At this point of the project dykes seem to follow pre-existing fractures to intrude the formations so the recognition of the fracture attitude is very important to prevent those intrusions at depths where the oil and gas is trapped.
This information was considered as a high value to improve the existing geological model, providing knowledge about the complex net of intrusive bodies by the accurate recognition of the type of intrusion and its attitude close to the borehole.
Barredo, S. P. (Instituto Tecnológico de Buenos Aires) | Sosa Massaro, A. (Instituto Tecnológico de Buenos Aires) | Fuenmayor, E. (Instituto Tecnológico de Buenos Aires) | Abalos, R. (Instituto Tecnológico de Buenos Aires) | Stinco, L. P. (Oleumpetra) | Abarzúa, F. (Universidad Nacional de San Juan)
Integrating field and laboratory data is possible if there are strong geologic criteria to relate them. This challenge demands understanding rocks from the fabric and mineralogy up to the architectural elements of rock bodies at a basinal scale. The geological properties of rocks, being them clastic, chemical or biochemical, influence reservoir quality and hydrocarbon producibility, but continental mudrocks/siltstones (shales) are by far more complex because of their depositional nature and highly variable vertical and lateral sedimentary characteristics. Grain size variability and sedimentary structures are common in these rocks. From outcrops, well logs and the source rocks of the Cuyana Basin (Argentina) could be characterized as deposited in lacustrine environments under a strong tectonic and climatic influence. Silty sandstones, limestones, massive and laminated bituminous shales developed in underfilled and balanced to overfilled lakes. They display parallel/inclined/rippled laminations, coarsening/fining upwards patterns, nodules, scour surfaces and pedogenic features. Total organic content may reach 14 % and corresponds to macro and micro floral remains, freshwater invertebrates and kerogen types I and II. These lithofacies are vertically stacked in patterns that can be related to cycles with different mechanical properties. In outcrops and with the help of seismic lines third order depositional sequences representing basin variations in accommodation space were recognized as low accommodation (LAS) to high accommodation (HAS) sequences developed in each of the three rifting stages. Using detailed information about mineralogy and fossil content climate was characterized and fourth order parasequences could be characterized. Fifth order (bedset-rhythms) cycles were interpreted on the basis of outcrops and well logs. Inorganic (especially clays) and organic content, pedogenic fabric, burrows and microfracturing represent weakness planes and as they vary according to these cycles, it was possible to model a mechanical cyclicity along the whole lacustrine column and to analyze their depositional controls. This integrated study has provided relevant data for the understanding of the geological and mechanical properties that will contribute to the optimization of fracture programs.
Cai, Hua (CNOOC Ltd.-Shanghai) | Huang, Daowu (CNOOC Ltd.-Shanghai) | Duan, Dongping (CNOOC Ltd.-Shanghai) | Cheng, Chao (CNOOC Ltd.-Shanghai) | Ruan, JianXin (CNOOC Ltd.-Shanghai) | Li, Yangfan (CNOOC Ltd.-Shanghai) | Zhang, Xianguo (China University of Petroleum-Beijing)
Generally, the favorable diagenetic facies belt of the reservoirs is the dessert for hydrocarbon exploration. Traditionally, the research of diagenetic facies is based on core analysis, as a result, it is difficult to make prediction under the condition of sparse wells and less cores. In order to solve this difficulty, the new method to predict the diagenetic facies should be researched.
In this research, the low permeability sandstone reservoirs of East China Offshore Gas Fields are selected as the research area, and three research steps have been done. First, by using the core analysis, ACR (Apparent Compaction Ratio) and ADR (Apparent Dissolution Ratio) are selected as the discriminant parameters for the diagenesis, and the quantitative standards are established. Second, the rock-electric relationships according to the diagenetic facies are established, the relationship of well logging parameters (GR, DT, CNCF, RT, DEN) vs. ACR, and the same well logging parameters vs. ADR can be matched by using BP neural network method. Accordingly, the ACR and ADR of the whole well can be obtained, and the diagenetic facies in accordance with the ACR and ADR can be predicted. Third, the relationship of well-log and seismic data can be established. After that, the relationship of seismic attributes (Ip - p wave impedance, Is - s wave impedance, Vp/Vs - p and s wave velocity ratio) vs. ACR, and the same seismic attributes vs. ADR can be matched. After the three steps, the favorable diagenetic facies belt can be predicted by using seismic attributes under the condition of sparse wells and less cores.
By using the above methods, the diagenetic facies in the research area can be divided into six types: mid dissolution and mid compaction; mid dissolution and mid-strong compaction; strong dissolution and strong compaction; mid-strong dissolution and strong compaction; shale-silty strong compaction; strong cementation. The previous three of the six types are selected as the favorable diagenetic facies. According to the quantitative standards of ACR & ADR, and the relationship of the seismic attributes vs. ACR & ADR, the diagenetic facies in the plane and vertical can be predicted by using seismic attributes. In the research area, three layers of Huagang formation have been selected by fitting the favorable diagenetic facies: Layer 1 (Shallow) corresponding to mid dissolution and mid compaction; Layer 2 (Mid) corresponding to mid dissolution and mid-strong compaction; Layer 3 (Deep) corresponding to strong dissolution and strong compaction. As a result, these three layers are considered to be the desserts for exploration and development.
This paper presents a new quantitative characterizing system for diagenetic facies by combing core-logging-seismic. Furthermore, a new method to quantitative characterizing diagenetic facies by using seismic attributes is established for the first time. The innovative content presented in this paper can provide theoretical references for exploration of sandstone reservoirs under the condition of sparse wells, and also provide complement for the diagenetic facies characterizing theories.
Dolomitization, as part of diagenesis of carbonate rocks, may or may not significantly enhance reservoir quality of the altered sediments. In this context, a diagenesis study was performed on Upper Cretaceous reservoir of an onshore oil field, Abu Dhabi, U.A.E. The paper elaborates facies related dolomitization and its selective influence on the reservoir quality enhancements. The framework of the study is based on detailed petrographic examination and description of 850 thin sections, isotopic compositions (C, O, Sr) of selected samples; and fluid inclusion microthermometry of dolomite formed in upper and middle reservoir units.
The study concluded that dolomitization of shoal grainstones and packstones resulted in coarse crystalline dolomite, which caused significant increase in reservoir porosity and permeability in the middle resercoir unit. Conversly, dolomitization of pretidal mudstones and wackestones resulted in microcrystalline dolomite, which has caused limted increase in the micro-porosity with little impact on permeability in the upper reservoir unit. Dolomite was formed during eo- and mesodiagenesis (Th = ca 65-90° C; salinity = 15-21 wt. % NaCl). Dolomitization of pretidal mudstones is suggested to have occurred in an evaporative setting, whereas dolomitization developed in packstones and grainstones of bioclastic shoal and subtidal sediments may have been driven by deepage reflux mechanisms. Consequently, dolomitization trend maps were produced for both middle and upper reservoir units. These dolomitization trend maps were than used as constrain to build the facies model to honor the diagenetic overprint. Blind test on integrated facies model revealed high predictiability in terms over reservoir quality distribution and production behavior in both upper and middle reservoir units. This in turn has added value to optimize field development stratergies with proper well placement into the reservoir.