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.

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.

Experimental Determination of the Shale Wettability

2020 ◽  
Author(s):  
Aliya Mukhametdinova ◽  
Natalia Bogdanovich ◽  
Alexey Cheremisin ◽  
Svetlana Rudakovskaya
Keyword(s):  
Contact Angle ◽  
Organic Content ◽  
Wetting Angle ◽  
Reservoir Rock ◽  
Initial Assessment ◽  
Reservoir Properties ◽  
Laboratory Methods ◽  
Thin Sections ◽  
Mean Values ◽  
Fluid Saturation

<p>In recent years, the share of unconventional reserves in global oil production has grown. Exploration and development of unconventional resources require novel effective laboratory methods for characterizing the reservoir properties. The study and analysis of local shale deposits such as Bazhenov Formation (BF) in Western Siberia is a priority among non-traditional reservoirs. Wettability of the reservoir rock is one of the most important factors affecting the residual saturation and filtration properties in the formation. However, as multiple petrophysical studies show, conventional laboratory methods for characterizing the wettability are not applicable for this type of formations.</p><p>In this work, the fluid saturation and wettability of BF rock samples were studied utilizing a nuclear magnetic resonance (NMR) and the method of determining the wetting contact angle by a surface drop. We have provided the petrographic description of rocks using ultrathin sections for grouping the samples. In addition, we used data on the organic content (TOC) obtained by the Rock-Eval method on a HAWK RW instrument (Wildcat Technologies) and the results of lithological typing on thin sections using an Axio Imager A2m polarizing microscope (Carl Zeiss) for detailed analysis of NMR and contact angle methods results.</p><p>To assess wettability by NMR, T2 relaxation curves were constructed for extracted (cleaned), kerosene-saturated and water-saturated samples. A comparison of the relaxation spectra for kerosene and water enabled evaluation of the wettability for each by T2 log mean values. The calculation of the wetting angle was carried out for samples before and after the extraction, which revealed minor changes in the nature of the rock wettability because of cleaning. Thus, for this type of rock, the drop method for determining wettability turned out to be significantly sensitive to the shape of the OM distribution in the rock. Correlations built on wettability (by NMR results and calculated wetting angle) vs. TOC and lithotyping illustrated the dependence of rock wettability behavior on both the lithotype and the TOC content.</p><p>The calculation of the wetting angle provided an initial assessment of the surface wettability of the rock and made it possible to establish the relationship between the wetting angle and the content of organic carbon (TOC), which is relevant for BF rocks. The lithological description of thin sections was used to highlight groups with a similar wettability of the rock. For the integral characteristics of the samples wettability, the NMR relaxometry method was proposed.</p>

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 Horizontal wellbore production profile evaluation by distributed fiber-optic temperature surveillance

2021 ◽  
Vol 6 (4) ◽  
pp. 81-91
Author(s):  
Andrey I. Ipatov ◽  
Mikhail I. Kremenetsky ◽  
Ilja S. Kaeshkov ◽  
Mikhail V. Kolesnikov ◽  
Alexander  A. Rydel ◽  
...  
Keyword(s):  
Fiber Optic ◽  
Phase Segregation ◽  
Gas Production ◽  
Fiber Optic Sensor ◽  
Well Testing ◽  
Reservoir Properties ◽  
Horizontal Wellbore ◽  
Long Term Monitoring ◽  
Term Monitoring

The main goal of the paper is demonstration of permanent downhole long-term monitoring capabilities for oil and gas production profile along horizontal wellbore in case of natural flow. The informational basis of the results obtained is the data of long-term temperature and acoustic monitoring in the borehole using a distributed fiber-optic sensor (DTS + DAS). Materials and methods. At the same time, flowing bottom-hole pressure and surface rates were monitored at the well for rate transient analysis, as well as acoustic cross-well interference testing [1], based on the results of which “well-reservoir” system properties were evaluated, the cross-well reservoir properties of the were estimated, and the possibility of cross-well testing using downhole DTS-DAS equipment was justified. The research results made it possible to assess reliability of DTS-DAS long-term monitoring analysis results in case of multiphase inflow and multiphase wellbore content. In particular, DTS-DAS results was strongly affected by the phase segregation in the near-wellbore zone of the formation. Conclusions. In the process of study, the tasks of inflow profile for each fluid phase evaluation, as well as its changes during the well production, were solved. The reservoir intervals with dominantly gas production have been reliably revealed, and the distribution of production along the wellbore has been quantified for time periods at the start of production and after production stabilization.

Seismic Data Analysis for Well Performance and Production Data Forecast: Massive Low-Relief Gas Reservoir Case Study

2021 ◽  
Author(s):  
Aleksei Anatolyevich Gorlanov ◽  
Dmitrii Yurevich Vorontsov ◽  
Aleksei Sergeevich Schetinin ◽  
Aleksandr Ivanovich Aksenov ◽  
Diana Gennadyevna Ovchinnikova
Keyword(s):  
Seismic Data ◽  
Seismic Attributes ◽  
Gas Production ◽  
Poor Correlation ◽  
Well Performance ◽  
Reservoir Properties ◽  
Gas Reservoir ◽  
Water Contact ◽  
Geological Conditions ◽  
Depth Analysis

Abstract In the process of developing massive gas reservoirs, gas-water contact (GWC) rise is inevitable, which leads to water-breakthrough in wells and declining daily gas production. Drilling horizontal sidetracks and new horizontal wells helps to maintain target production levels. The direction of drilling a horizontal well section largely determines its efficiency. In complex geological conditions, a detailed analysis of seismic data in the drilling area helps to reduce drilling risks and achieve planned starting parameters. The integration of seismic data in geological models is often limited by poor correlation between reservoir properties from wells and seismic attributes. Flow simulation models use seismic data based on the assumptions made by the geological engineers. The study uses a cyclic approach to geological modeling: realizations include in-depth analysis of seismic data and well performance profiles. Modern software modules were used to automatically check the compliance of the geological realization with the development history, as well as to assess the uncertainties. This made it possible to obtain good correlation between well water cut and seismic attributes and to develop a method for determining the presence of shale barriers and "merging windows" of a massive gas reservoir with water-saturated volumes.

scholarly journals Estimation of reservoir properties from seismic data by smooth neural networks

Geophysics ◽  
2003 ◽  
Vol 68 (6) ◽  
pp. 1969-1983 ◽  
Author(s):  
M. M. Saggaf ◽  
M. Nafi Toksöz ◽  
H. M. Mustafa
Keyword(s):  
Seismic Data ◽  
Reservoir Characterization ◽  
Back Propagation ◽  
Reservoir Rock ◽  
Seismic Survey ◽  
Rock Properties ◽  
Reservoir Properties ◽  
Network Parameters ◽  
Generalization Problem ◽  
Validation Tests

The performance of traditional back‐propagation networks for reservoir characterization in production settings has been inconsistent due to their nonmonotonous generalization, which necessitates extensive tweaking of their parameters in order to achieve satisfactory results and avoid overfitting the data. This makes the accuracy of these networks sensitive to the selection of the network parameters. We present an approach to estimate the reservoir rock properties from seismic data through the use of regularized back propagation networks that have inherent smoothness characteristics. This approach alleviates the nonmonotonous generalization problem associated with traditional networks and helps to avoid overfitting the data. We apply the approach to a 3D seismic survey in the Shedgum area of Ghawar field, Saudi Arabia, to estimate the reservoir porosity distribution of the Arab‐D zone, and we contrast the accuracy of our approach with that of traditional back‐propagation networks through cross‐validation tests. The results of these tests indicate that the accuracy of our approach remains consistent as the network parameters are varied, whereas that of the traditional network deteriorates as soon as deviations from the optimal parameters occur. The approach we present thus leads to more robust estimates of the reservoir properties and requires little or no tweaking of the network parameters to achieve optimal results.

scholarly journals The features of the geological structure of the Verkhnechonsky oil and gas condensate field and their influence on the field development and operation system

2020 ◽  
Vol 43 (3) ◽  
pp. 350-363
Author(s):  
L. A. Rapatskaya
Keyword(s):  
Oil And Gas ◽  
Horizontal Wells ◽  
Geological Structure ◽  
Field Structure ◽  
Gas Condensate ◽  
Reservoir Properties ◽  
Reservoir Water ◽  
Horizontal Drilling ◽  
Development System ◽  
Field Development

The study aims to analyze the relationship between the redetermination of the complexity of the geological structure of the Verkhnechonsky oil and gas condensate field and the schedule adjustment of the field development plans. The paper uses the data on the exploration and production wells obtained from the pilot operation of JSC Verkhnechonskneftegaz, the geophysical work results, and the research materials publicly available in the press. The geological structure of the Verhnechonskoye oil and gas condensate field is unique in its complexity. This is due to the following factors: a combination of tectonic disturbances accompanied by the intrusion of traps; high mineralization of the reservoir water; sharp variability of the filtration and reservoir properties of the producing horizons by area and section due to the unevenness of the lithological composition of the reservoirs, their salinization and complete pinch-out. The development system of any field should take into account the peculiarities of the field’s tectonic and lithological-facies structure, and meet specific technical and economic requirements for drilling and operating wells. The complexity of the field structure requires a thorough selection of a development system that inevitably changes as the features of the field structure are studied, e.g. vertical drilling suggested at the initial stage of the filed development was shortly after replaced with inclined-horizontal drilling with the calculation of two options. Within the pilot operation project of the Verkhnechonsky field, JSC Verkhnechonskneftegaz has developed two variants of uniform grids of directional and horizontal wells with pattern flooding for the most explored deposits of the Verkhnechonsky horizon of blocks I and II. Because of the intensive processes of the reservoirs’ secondary salinization, the flooding method required a study of the reservoir water composition. However, the proposed drilling plan using a downhole engine and gamma-ray logging could not ensure the wellbores ducting through the most productive sections of the horizon, therefore, the flow rates of some directional and horizontal wells were not high enough. To increase the drilling efficiency, the specialists of the Drilling Department (JSC Verhnechonskneftegaz), together with the Department of Geology and Field Development (Schlumberger Ltd.), proposed a new methodology that increases the drilling efficiency by using a rotary-controlled system, logging-while-drilling, and geosteering. Thus, the development system of the Verkhnechonsky oils and gas condensate field was changing in the process of specifying the field’s geological structure, anisotropy reservoir properties, and the thickness of the producing horizons in size and cut, their salinization and pinch-out, and the composition of the reservoir waters.

scholarly journals Study of Gas Wells Operation Regimes in Complicated Conditions

2021 ◽  
Vol 21 (1) ◽  
pp. 36-41
Author(s):  
Maksim A. Popov ◽  
◽  
Dmitriy G. Petrakov ◽  
Keyword(s):  
Gas Production ◽  
Point Of View ◽  
Reservoir Rock ◽  
Rock Properties ◽  
Internal Stresses ◽  
Negative Consequences ◽  
Sand Production ◽  
Gas Wells ◽  
Initial State ◽  
Formation Zone

The influence of reservoir rock properties on sand production in wells is considered. It was concluded that the rock should be considered rather not from the point of view of its strength, but from the point of view of the type of cementitious substance and its distribution. When predicting sand production, it is necessary to take into account the internal stresses of the rocks, as well as the change in these stresses during drilling, perforation and operation of the formation due to the violation of their initial state. Within the framework of this work, an analysis of the main causes of sand production during the operation of gas wells and the negative consequences of sand production for gas production equipment is presented. It has been established that water breakthrough, formation depletion, pressure drop at the bottom of the wells due to their frequent shutdown are the main prerequisites for the removal of sand from the bottomhole formation zone. Sand production is associated with such negative consequences as plugging in wells, erosion of underground and surface equipment, collapse of the top of the bottomhole formation zone and production strings. The main technologies for the prevention and elimination of accidents associated with the removal of mechanical particles from the reservoir are considered. Based on the research results, an algorithm was proposed for selecting technological modes of well operation in conditions of water and sand. The parameters for choosing the optimal operating mode of a gas well are substantiated, in which sand is not extracted with the subsequent disabling of downhole and wellhead equipment, the integrity of the bottomhole zone is not violated, and the well is not selfcontained. The results obtained can be applied to improve the efficiency of gas wells operation and predict their trouble-free operation.

scholarly journals Investigation of the influence of the carbon dioxide (CO2) injection rate on the activity of the water pressure system during gas condensate fields development

2021 ◽  
Vol 230 ◽  
pp. 01011
Author(s):  
Serhii Matkivskyi ◽  
Oleksandr Kondrat ◽  
Oleksandr Burachok
Keyword(s):  
Carbon Dioxide ◽  
Water Pressure ◽  
Gas Production ◽  
Gas Condensate ◽  
Co2 Injection ◽  
Final Decision ◽  
Water Production ◽  
Carbon Dioxide Injection ◽  
Pressure System ◽  
Water Contact

The development of gas condensate fields under the conditions of elastic water drive is characterized by uneven movement of the gas-water. Factors of hydrocarbon recovery from producing reservoirs which are characterized by the active water pressure drive on the average make up 50-60%. To increase the efficiency of fields development, which are characterized by an elastic water drive, a study of the effect of different volumes of carbon dioxide injection at the gas-water contact on the activity of the water pressure system and the process of flooding producing wells was carried out. Using a three-dimensional model, the injection of carbon dioxide into wells located at the boundary of gas-water contact with flow rates from 20 to 500 thousand m3/day was investigated. Analyzing the simulation data, it was found that increasing the volume of carbon dioxide injection provides an increase in accumulated gas production and a significant reduction in water production. The main effect of the introduction of this technology is achieved by increasing the rate of carbon dioxide injection to 300 thousand m3/day. The set injection rates allowed us to increase gas production by 67% and reduce water production by 83.9% compared to the corresponding indicators without injection of carbon dioxide. Taking into account above- mentioned, the final decision on the introduction of carbon dioxide injection technology and optimal technological parameters of producing and injection wells operation should be made on the basis of a comprehensive technical and economic analysis using modern methods of the hydrodynamic modeling of reservoir systems.

scholarly journals Impact of Diagenesis on the Reservoir Properties of the Cretaceous Sandstones in the Southern Bredasdorp Basin, Offshore South Africa

Minerals ◽  
2020 ◽  
Vol 10 (9) ◽  
pp. 757
Author(s):  
Temitope Love Baiyegunhi ◽  
Kuiwu Liu ◽  
Oswald Gwavava ◽  
Christopher Baiyegunhi
Keyword(s):  
Oil And Gas ◽  
Gas Production ◽  
Reservoir Quality ◽  
Reservoir Properties ◽  
Oil And Gas Production ◽  
Thin Sections ◽  
Hydrocarbon Reservoir ◽  
Porosity And Permeability ◽  
The Impact

The Cretaceous sandstone in the Bredasdorp Basin is an essential potential hydrocarbon reservoir. In spite of its importance as a reservoir, the impact of diagenesis on the reservoir quality of the sandstones is almost unknown. This study is undertaken to investigate the impact of digenesis on reservoir quality as it pertains to oil and gas production in the basin. The diagenetic characterization of the reservoir is based on XRF, XRD SEM + EDX, and petrographic studies of 106 thin sections of sandstones from exploration wells E-AH1, E-AJ1, E-BA1, E-BB1 and E-D3 in the basin. The main diagenetic processes that have affected the reservoir quality of the sandstones are cementation by authigenic clay, carbonate and silica, growth of authigenic glauconite, dissolution of minerals and load compaction. Based on the framework grain–cement relationships, precipitation of the early calcite cement was either accompanied or followed up by the development of partial pore-lining and pore-filling clay cements, particularly illite. This clay acts as pore choking cement, which reduces porosity and permeability of the reservoir rocks. The scattered plots of porosity and permeability versus cement + clays show good inverse correlations, suggesting that the reservoir quality is mainly controlled by cementation and authigenic clays.

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