AWAKENING OF A SLEEPING GIANT: SUNRISE- TROUBADOUR GAS-CONDENSATE FIELD

2000 ◽  
Vol 40 (1) ◽  
pp. 417 ◽  
Author(s):  
R.J. Seggie ◽  
R.B. Ainsworth ◽  
D.A.Johnson ◽  
J.P.M. Koninx ◽  
B. Spaargaren ◽  
...  
Keyword(s):  
Gas Condensate ◽  
Probabilistic Methods ◽  
Rock Properties ◽  
Quality Data ◽  
Reservoir Properties ◽  
Water Contact ◽  
Fluid Analysis ◽  
Avo Inversion ◽  
Active Tectonism ◽  
Key Aspects

The Sunrise and Troubadour fields form a complex of giant gas-condensate accumulations located in the Timor Sea some 450 km northwest of Darwin. Left unappraised for almost a quarter of a century since discovery, recently renewed attention has brought these stranded hydrocarbon accumulations to the point of comm-ercialisation.A focussed appraisal program during 1997–1999 driven by expectations of growth in LNG and domestic gas markets, involved the acquisition and processing of an extensive grid of modern 2D seismic and the drilling, coring and testing of three wells. The aim of this program was to quantify better both in-place hydrocarbon volumes (reservoir properties and their distribution) and hydrocarbon recovery efficiency (gas quality and deliverability). Maximum value has been extracted from these data via a combination of deterministic and probabilistic methods, and the integration of analyses across all disciplines.This paper provides an overview of these efforts, describes the fields and details major subsurface uncertainties. Key aspects are:3D, object-based geological modelling of the reservoir, covering the spectrum of plausible sedimentological interpretations.Convolution of rock properties, derived from seismic (AVO) inversion, with 3D geological model realisations to define reservoir properties in inter-well areas.Incorporation of faults (both seismically mapped and probabilistically modelled sub-seismic faults) into both the static 3D reservoir models and the dynamic reservoir simulations.Interpretation of a tilted gas-water contact apparently arising from flow of water in the Plover aquifer away from active tectonism to the north.Extensive gas and condensate fluid analysis and modelling.Scenario-based approach to dynamic modelling.In summary, acquisition of an extensive suite of quality data during the past two-three years coupled with novel, integrated, state-of-the-art analysis of the subsurface has led to a major increase in estimates of potentially recoverable gas and condensate. Improved volumetric confidence in conjunction with both traditional and innovative engineering design (e.g. Floating Liquefied Natural Gas technology) has made viable a range of possible commercial developments from 2005 onwards.

Specifics of Implemented Development System of Shtormove Field Black Sea Offshore

2021 ◽  
Author(s):  
Mykhailo Mykytovych Bahniuk ◽  
Vitaliy Mykolaiovych Vladyka ◽  
Oleh Stepanovych Hotsynets ◽  
Oleksandra Olehivna Dmyshko ◽  
Maksym Volodymyrovych Dorokhov ◽  
...  
Keyword(s):  
Estimation Method ◽  
Gas Production ◽  
Gas Condensate ◽  
Reservoir Rock ◽  
Rock Properties ◽  
Well Testing ◽  
Reservoir Properties ◽  
Water Contact ◽  
Thin Sections ◽  
Development System

Abstract The development system of the main hydrocarbon deposit of the Shtormove field was designed taking into account the change in reservoir rock properties in horizontal and vertical sections of the gas-saturated interval. Based on the results of core analyses and interpretation of logging data from exploration and appraisal wells, maximum porosity values were assigned to the top part of the deposit, with lower porosity values assigned closer to the gas-water contact area. The analyzed thin sections demonstrated vertical and subvertical fractures, as well as multiple pores and dissolution vugs. Most of the fractures occur in the top part of the gas-condensate deposit. Natural fractures in the rocks of the productive interval were confirmed by well testing using a steady flow analysis. Taking into account the determined reservoir properties’ distribution pattern in the gas-condensate deposit II, the wells were drilled in the top part of the deposit from a fixed offshore platform during the pilot development period. During this period, the estimated recoverable gas reserves’ values matched the values obtained using the volumetric estimation method. In the following years, in order to increase the gas recovery rate, the infilling production wells were drilled in the top part of the deposit. Based on the analysis of the development, it was determined that the addition of new wells had little effect on the performance of existing ones. As a result, attributable to infill drilling in the top part of the deposit, the annual gas production increased. Given the similarity of the geological model and distribution of reservoir properties, the implemented development system of the Shtormove field should be recommended for new development targets.

Factors Controlling Porosity Permeability Relationship for Reservoir Quality Prediction: A Case Study of Malay Basin Reservoir, Malaysia

2021 ◽  
Author(s):  
Fadzlin Hasani Kasim ◽  
Budi Priyatna Kantaatmadja ◽  
Wan Nur Wan M Zainudin ◽  
Amita Ali ◽  
Hasnol Hady Ismail ◽  
...  
Keyword(s):  
Reservoir Characterization ◽  
Visual Analysis ◽  
Mineral Dissolution ◽  
Rock Properties ◽  
Reservoir Quality ◽  
Hydrocarbon Potential ◽  
Lower Grade ◽  
Reservoir Properties ◽  
Reservoir Evaluation ◽  
Porosity And Permeability

Abstract Predicting the spatial distribution of rock properties is the key to a successful reservoir evaluation for hydrocarbon potential. However, a reservoir with a complex environmental setting (e.g. shallow marine) becomes more challenging to be characterized due to variations of clay, grain size, compaction, cementation, and other diagenetic effects. The assumption of increasing permeability value with an increase of porosity may not be always the case in such an environment. This study aims to investigate factors controlling the porosity and permeability relationships at Lower J Reservoir of J20, J25, and J30, Malay Basin. Porosity permeability values from routine core analysis were plotted accordingly in four different sets which are: lithofacies based, stratigraphic members based, quartz volume-based, and grain-sized based, to investigate the trend in relating porosity and permeability distribution. Based on petrographical studies, the effect of grain sorting, mineral type, and diagenetic event on reservoir properties was investigated and characterized. The clay type and its morphology were analyzed using X-ray Diffractometer (XRD) and Spectral electron microscopy. Results from porosity and permeability cross-plot show that lithofacies type play a significant control on reservoir quality. It shows that most of the S1 and S2 located at top of the plot while lower grade lithofacies of S41, S42, and S43 distributed at the middle and lower zone of the plot. However, there are certain points of best and lower quality lithofacies not located in the theoretical area. The detailed analysis of petrographic studies shows that the diagenetic effect of cementation and clay coating destroys porosity while mineral dissolution improved porosity. A porosity permeability plot based on stratigraphic members showed that J20 points located at the top indicating less compaction effect to reservoir properties. J25 and J30 points were observed randomly distributed located at the middle and bottom zone suggesting that compaction has less effect on both J25 and J30 sands. Lithofacies description that was done by visual analysis through cores only may not correlate-able with rock properties. This is possibly due to the diagenetic effect which controls porosity and permeability cannot visually be seen at the core. By incorporating petrographical analysis results, the relationship between porosity, permeability, and lithofacies can be further improved for better reservoir characterization. The study might change the conventional concept that lower quality lithofacies does not have economic hydrocarbon potential and unlock more hydrocarbon-bearing reserves especially in these types of environmental settings.

scholarly journals Integration of geostatistical realizations in data assimilation and reduction of uncertainty process using genetic algorithm combined with multi-start simulated annealing

2019 ◽  
Vol 74 ◽  
pp. 73 ◽  
Author(s):  
Célio Maschio ◽  
Denis José Schiozer
Keyword(s):  
Genetic Algorithm ◽  
Simulated Annealing ◽  
Data Assimilation ◽  
Relative Permeability ◽  
Reduction Process ◽  
Local Perturbation ◽  
Reservoir Properties ◽  
Water Contact ◽  
Starting Point ◽  
Rock Compressibility

This paper introduces a new methodology, combining a Genetic Algorithm (GA) with multi-start simulated annealing to integrate Geostatistical Realizations (GR) in data assimilation and uncertainty reduction process. The proposed approach, named Genetic Algorithm with Multi-Start Simulated Annealing (GAMSSA), comprises two parts. The first part consists of running a GA several times, starting with certain number of geostatistical realizations, and the second part consists of running the Multi-Start Simulated Annealing with Geostatistical Realizations (MSSAGR). After each execution of GA, the best individuals of each generation are selected and used as starting point to the MSSAGR. To preserve the diversity of the geostatistical realizations, a rule is imposed to guarantee that a given realization is not repeated among the selected individuals from the GA. This ensures that each Simulated Annealing (SA) process starts from a different GR. Each SA process is responsible for local improvement of the best individuals by performing local perturbation in other reservoir properties such as relative permeability, water-oil contact, etc. The proposed methodology was applied to a complex benchmark case (UNISIM-I-H) based on the Namorado Field, located in the Campos Basin, Brazil, with 500 geostatistical realizations and other 22 attributes comprising relative permeability, oil-water contact, and rock compressibility. Comparisons with a conventional GA algorithm are also shown. The proposed method was able to find multiple solutions while preserving the diversity of the geostatistical realizations and the variability of the other attributes. The matched models found by the GAMSSA method provided more reliable forecasts when compared with the matched models found by the GA.

Advanced methods for the evaluation of a hybrid-type unconventional play: The Bakken petroleum system

2016 ◽  
Vol 4 (2) ◽  
pp. SF93-SF111 ◽  
Author(s):  
Iain Pirie ◽  
Jack Horkowitz ◽  
Gary Simpson ◽  
John Hohman
Keyword(s):  
Evaluation Methods ◽  
Petroleum System ◽  
Oil Field ◽  
Probabilistic Methods ◽  
Rock Properties ◽  
Depth Interval ◽  
Free Fluid ◽  
Formation Evaluation ◽  
Hybrid Type ◽  
Petrophysical Evaluation

Hybrid-type plays such as the Bakken petroleum system (BPS) can be particularly challenging from an interpretation, completion, or production perspective due to the mix of conventional and unconventional elements coexisting within a relatively short depth interval. In the BPS, conventional aspects include the presence of separate reservoir intervals, which, depending on your location within the basin, may include the Scallion, Middle Bakken, Sanish, and Three Forks. Unconventional aspects include the Lower Bakken and Upper Bakken shales, which are organic-rich shales comprising source rock and reservoir. Developing an accurate petrophysical evaluation of these formations requires a priori knowledge of the mineralogy, fluids, and geomechanical properties such that appropriate logging measurements, core analysis methods, and interpretation techniques can be obtained and used. During the development phase of an oil field, the log and core measurements being acquired and the petrophysical evaluation being performed may vary significantly from well to well across the field. Some wells may have triple-combo wireline or logging-while-drilling measurements consisting of bulk density, neutron porosity, and induction or laterolog resistivity, supplemented with a total gamma ray measurement. Borehole sonic logs may also have been acquired in some wells primarily for seismic calibration, geomechanical modeling, and hydraulic stimulation design. If the “standard” suite of measurements and petrophysical evaluation being provided fail to accurately represent the true complexity of the formations being evaluated, the asset valuation will, in most cases, be negatively impacted. Our formation evaluation of the BPS led to the identification of unique petrophysical challenges for each of the formations comprising the BPS. Traditional formation evaluation methods were applied to the BPS based on triple-combo measurements, a traditional petrophysical analysis, and the evaluation of net feet of pay. Advanced evaluation methods and techniques were then applied to address the petrophysical complexities identified with core evaluation, advanced log measurements, and discrepancies between the two. New petrophysical models were developed and fine-tuned to address the shortcomings of the simple models, and the net feet of pay were reevaluated using these new models. The detailed formation evaluation program used to characterize the BPS consisted of standard triple-combo logs supplemented with advanced downhole measurements including: (1) triaxial resistivity for thin-bed analysis, (2) nuclear magnetic resonance for porosity, free-fluid, and kerogen identification, (3) dielectric dispersion for water saturation, (4) geochemical spectroscopy for mineralogy and total organic carbon, and (5) dipole sonic for dynamic rock properties. Petrophysical models were developed using deterministic and probabilistic methods to integrate the measurements acquired for the most accurate analysis of porosity, saturation, and mineralogy and to best describe the hydrocarbon production potential of the BPS.

Seismic inversion for geologic fractures and fractured media

Geophysics ◽  
2017 ◽  
Vol 82 (5) ◽  
pp. C145-C161 ◽  
Author(s):  
Xiaoqin Cui ◽  
Edward S. Krebes ◽  
Laurence R. Lines
Keyword(s):  
Seismic Data ◽  
Wave Reflection ◽  
Rock Properties ◽  
Reflection And Transmission ◽  
Transmission Coefficients ◽  
Avo Inversion ◽  
Impedance Contrast ◽  
Fractured Medium ◽  
Pp Wave ◽  
Contact Part

Amplitude variation with offset (AVO) inversion attempts to use the available surface seismic data to estimate the density, P-wave velocity, and S-wave velocity of the earth model. Under linear slip interface theory, synthetic seismograms for models with fractures prove that fractures are also reflection generators. Consequently, observed reflections are not necessarily due to lithologic variations only, but they could be due in part to the effect of fractures. To obtain approximate equations for AVO inversion for fractured media, denoted by AVO with fracture (AVOF), we derived new equations for PP-wave reflection and transmission coefficients that are based on nonwelded contact boundary conditions. In particular, along with the fracture compliances, azimuth has also been taken into account in the equations because the fractures can have any orientation. The new approximate AVOF equations for a horizontally fractured medium with impedance contrast are developed by simplifying the equations for the new PP-wave reflection and transmission coefficients. In the new approximate AVOF equations, the reflection coefficients are divided into a welded contact part (a conventional impedance contrast part) and a nonwelded contact part (a fracture part). This makes the equations flexible enough to separately invert for the rock properties of the fracture and the background medium in the case of a fractured medium with impedance contrast. The new approximate AVOF equations state that fractures could cause the seismic reflectivity to be frequency dependent, and that the fractures not only influence the wave amplitude but also change the wave phase. The linear least-squares and nonlinear conjugate gradient inversion algorithms are applied to estimate the elastic reflectivity using the new approximate AVOF equations. The inverted results for seismic data for a horizontally fractured medium with impedance contrast are evaluated to find a more accurate delineation of the subsurface rock properties.

Upscaling Saturation-Height Technology for Arab Carbonates for Improved Transition-Zone Characterization

2010 ◽  
Vol 14 (01) ◽  
pp. 11-24 ◽  
Author(s):  
J.J.M.. J.M. Buiting
Keyword(s):  
Capillary Pressure ◽  
Rock Properties ◽  
Well Log ◽  
Pore System ◽  
Major Step ◽  
Reservoir Properties ◽  
Persistent Problem ◽  
High Productivity ◽  
Transition Zones ◽  
Analytic Expression

Summary Much of the oil in Saudi Arabia is stored in giant and supergiant multireservoir fields. The Arab-D limestone is the most important of these and the most prolific. The large volumes, excellent porosity, and high productivity of these reservoirs do not mask the fact that these carbonates have complex pore systems. The problems associated with heterogeneous carbonate reservoirs pose significant and longstanding modeling complications that are not yet fully addressed by the industry. One important difficulty is the accurate modeling of the substantial transition zones present above the freewater levels (FWLs). In these giant fields, these transition zones hold large amounts of oil and are important commercial objectives. Commerciality requires accurate assessment of saturations and rock properties. Standard J-function methods are inadequate to model the well-log observed saturation-height behavior in the transition zones. It is necessary to characterize and account for the pore system variations and scale when modeling the saturation behavior of large rock volumes. The reservoir properties of geocells and wellbores must be reconciled with the measurements on core plugs. The measurements performed on these tiny pieces of rock need to be upscaled to represent the reservoir bulk properties. Upscaling of core-plug-scale, laboratory measured porosimetry data and transport properties has been a general and persistent problem since the beginning of reservoir simulation. This critical step has been handled, over the years, using a wide variety of numerical computational schemes, approximations, and empirical methods. In this paper, we take the different and very specific approach of upscaling the capillary pressure data for the Arab-D limestone. We base the approach on the availability of a large amount of mercury (Hg) -injection data and statistical analysis thereof, obtained by fitting hundreds of individual core plugs to Thomeer functions. For the Arab-D limestone, and similar carbonates, we derive a closed-form analytic expression for the upscaled capillary pressure function, which has significant implications for improving transitionzone hydrocarbon-volume estimates for this important petroleum system. The analytic expression also offers major efficiencies compared with other methods used by petroleum engineers, provided that the pore systems are adequately investigated and statistically characterized. A key result of the upscaled formalism is that reservoir cells, consisting of a large variation of pore systems, will start to fill with hydrocarbons much closer to the FWL than when using saturation-height functions based on simple averaged pore system parameter values. Therefore, transition zones for upscaled reservoir elements (and well-log volumes) are thicker than simple calculations based on data from single core plugs would indicate. The accurate upscaling of pore-system architecture is a major step toward the full understanding of the fluid-rock interactions of giant-field transition zones in the Middle East and is an industry technical milestone.

scholarly journals Geophysical imaging of porosity variations in the Danish North Sea chalk

2008 ◽  
Vol 15 ◽  
pp. 17-20 ◽  
Author(s):  
Tanni Abramovitz
Keyword(s):  
North Sea ◽  
Seismic Reflection ◽  
Seismic Inversion ◽  
Rock Properties ◽  
Well Log ◽  
Reservoir Properties ◽  
Seismic Reflection Data ◽  
Log Data ◽  
The North ◽  
The North Sea

More than 80% of the present-day oil and gas production in the Danish part of the North Sea is extracted from fields with chalk reservoirs of late Cretaceous (Maastrichtian) and early Paleocene (Danian) ages (Fig. 1). Seismic reflection and in- version data play a fundamental role in mapping and characterisation of intra-chalk structures and reservoir properties of the Chalk Group in the North Sea. The aim of seismic inversion is to transform seismic reflection data into quantitative rock properties such as acoustic impedance (AI) that provides information on reservoir properties enabling identification of porosity anomalies that may constitute potential reservoir compartments. Petrophysical analyses of well log data have shown a relationship between AI and porosity. Hence, AI variations can be transformed into porosity variations and used to support detailed interpretations of porous chalk units of possible reservoir quality. This paper presents an example of how the chalk team at the Geological Survey of Denmark and Greenland (GEUS) integrates geological, geophysical and petrophysical information, such as core data, well log data, seismic 3-D reflection and AI data, when assessing the hydrocarbon prospectivity of chalk fields.

scholarly journals Effects of the rate of natural gas production on the recovery factor during carbon dioxide injection at the initial gas-water contact

2021 ◽  
Vol 1 (3(57)) ◽  
pp. 6-11
Author(s):  
Serhii Matkivskyi
Keyword(s):  
Carbon Dioxide ◽  
Natural Gas ◽  
Gas Production ◽  
Gas Condensate ◽  
Recovery Factor ◽  
Formation Water ◽  
Hydrocarbon Gases ◽  
Water Contact ◽  
Natural Gas Production ◽  
Gas Recovery

The object of research is gas condensate reservoirs, which is being developed under the conditions of the manifestation of the water drive of development and the negative effect of formation water on the process of natural gas production. The results of the performed theoretical and experimental studies show that a promising direction for increasing hydrocarbon recovery from fields at the final stage of development is the displacement of natural gas to producing wells by injection non-hydrocarbon gases into productive reservoirs. The final gas recovery factor according to the results of laboratory studies in the case of injection of non-hydrocarbon gases into productive reservoirs depends on the type of displacing agent and the level heterogeneity of reservoir. With the purpose update the existing technologies for the development of fields in conditions of the showing of water drive, the technology of injection carbon dioxide into productive reservoirs at the boundary of the gas-water contact was studied using a digital three-dimensional model of a gas condensate deposit. The study was carried out for various values of the rate of natural gas production. The production well rate for calculations is taken at the level of 30, 40, 50, 60, 70, 80 thousand m3/day. Based on the data obtained, it has been established that an increase in the rate of natural gas production has a positive effect on the development of a productive reservoir and leads to an increase in the gas recovery factor. Based on the results of statistical processing of the calculated data, the optimal value of the rate of natural gas production was determined when carbon dioxide is injected into the productive reservoir at the boundary of the gas-water contact is 55.93 thousand m3/day. The final gas recovery factor for the optimal natural gas production rate is 64.99 %. The results of the studies carried out indicate the technological efficiency of injecting carbon dioxide into productive reservoirs at the boundary of the gas-water contact in order to slow down the movement of formation water into productive reservoirs and increase the final gas recovery factor.

scholarly journals Unlocking Inventory Data Capture, Sharing and Reuse: The Humboldt Extension to Darwin Core

2021 ◽  
Vol 5 ◽  
Author(s):  
Yanina Sica ◽  
Paula Zermoglio
Keyword(s):  
Relevant Information ◽  
Task Group ◽  
Quality Data ◽  
Systematic Sampling ◽  
Sampling Effort ◽  
Inventory Data ◽  
Biodiversity Data ◽  
Darwin Core ◽  
Rich Data ◽  
Key Aspects

Biodiversity inventories, i.e., recording multiple species at a specific place and time, are routinely performed and offer high-quality data for characterizing biodiversity and its change. Digitization, sharing and reuse of incidental point records (i.e., records that are not readily associated with systematic sampling or monitoring, typically museum specimens and many observations from citizen science projects) has been the focus for many years in the biodiversity data community. Only more recently, attention has been directed towards mobilizing data from both new and longstanding inventories and monitoring efforts. These kinds of studies provide very rich data that can enable inferences about species absence, but their reliability depends on the methodology implemented, the survey effort and completeness. The information about these elements has often been regarded as metadata and captured in an unstructured manner, thus making their full use very challenging. Unlocking and integrating inventory data requires data standards that can facilitate capture and sharing of data with the appropriate depth. The Darwin Core standard (Wieczorek et al. 2012) currently enables reporting some of the information contained in inventories, particularly using Darwin Core Event terms such as samplingProtocol, sampleSizeValue, sampleSizeUnit, samplingEffort. However, it is limited in its ability to accommodate spatial, temporal, and taxonomic scopes, and other key aspects of the inventory sampling process, such as direct or inferred measures of sampling effort and completeness. The lack of a standardized way to share inventory data has hindered their mobilization, integration, and broad reuse. In an effort to overcome these limitations, a framework was developed to standardize inventory data reporting: Humboldt Core (Guralnick et al. 2018). Humboldt Core identified three types of inventories (single, elementary, and summary inventories) and proposed a series of terms to report their content. These terms were organized in six categories: dataset and identification; geospatial and habitat scope; temporal scope; taxonomic scope; methodology description; and completeness and effort. While originally planned as a new TDWG standard and being currently implemented in Map of Life (https://mol.org/humboldtcore/), ratification was not pursued at the time, thus limiting broader community adoption. In 2021 the TDWG Humboldt Core Task Group was established to review how to best integrate the terms proposed in the original publication with existing standards and implementation schemas. The first goal of the task group was to determine whether a new, separate standard was needed or if an extension to Darwin Core could accommodate the terms necessary to describe the relevant information elements. Since the different types of inventories can be thought of as Events with different nesting levels (events within events, e.g., plots within sites), and after an initial mapping to existing Darwin Core terms, it was deemed appropriate to start from a Darwin Core Event Core and build an extension to include Humboldt Core terms. The task group members are currently revising all original Humboldt Core terms, reformulating definitions, comments, and examples, and discarding or adding new terms where needed. We are also gathering real datasets to test the use of the extension once an initial list of revised terms is ready, before undergoing a public review period as established by the TDWG process. Through the ratification of Humboldt Core as a TDWG extension, we expect to provide the community with a solution to share and use inventory data, which improves biodiversity data discoverability, interoperability and reuse while lowering the reporting burden at different levels (data collection, integration and sharing).

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