Reservoir Interval Research Articles

Depositional environments and sequence stratigraphy of the Arab Formation, Persian Gulf, Offshore Iran

The carbonate-evaporite sequence of the Arab Formation constitutes the important reservoir unit in the Persian Gulf and adjacent area. The paper aims to present detail facies characteristics, depositional environment and sequence stratigraphic analysis of the Arab Formation in an oil field in the Persian Gulf. A total of 12 microfacies (MF) and 3 dolomitic (diagenetic) facies (DF) were identified, and are interpreted as a homoclinal carbonate ramp platform. The Arab Formation is divided into four third order sequences corresponding to main reservoir intervals (Arab-A, B, C, D). The results highly correlate with the sequences of local and regional studies in the Arabian Plate. It is probably due to the cake layer nature of the Arab Formation and high impact of the world eustatic sea-level fluctuations (global curves) on the facies stacking pattern.

Integrated velocity and attenuation model building: Sakhalin case study

Shallow gas accumulations with varied spatial distribution and scales cause amplitude loss and phase distortion in seismic images in underlying reservoir intervals. We present an integrated velocity and attenuation (defined by the quality factor Q) model-building workflow to address the imaging challenges in a shallow-water data set acquired offshore Sakhalin Island, Russia. As part of the workflow, we use full-waveform inversion (FWI) to capture fine details of the velocity and Q models. We achieve a step change in image quality improvement and amplitude fidelity enhancement by leveraging the workflow. This image enhancement improves subsurface interpretation and influences well placement, subsurface model building, and depletion plan optimization. Key to this success is not only the advanced model-building tool kit, which includes FWI and tomography, but also the optimal integration of the tools specifically tailored for the geologic setting and imaging challenges offshore Sakhalin Island.

Effect of petrography and diagenesis on the sandstone reservoir quality: a case study of the Middle Miocene Kareem Formation in the North Geisum oil field, Gulf of Suez, Egypt

Kareem Formation is one of the most important hydrocarbon reservoirs in the Gulf of Suez. It contributes significantly to the total Egyptian oil production; therefore, the current work is to emphasise the influence of siliclastic facies types and their diagenetic processes on the reservoir quality of the Kareem Formation. A comprehensive log and core analyses were used to determine both the petrophysical and petrographical characteristics. Three classic facies have been identified: two sandstone facies with reservoir potential and one shale facies. Facies I is coarse-grained sandstone with high-angle cross-bedding, distributary/braided channel deposits on the active part of a mid-submarine fan lobe and is represented by beds of (Shagar Member). Facies II is fine-grained sandy beds represented by low-angle crudely, cross-bedded sandstone encountered in the Rahmi Member. Facies III is mainly shale and recorded in the Rahmi clastic zone. Petrographically, the quartz arenite microfacies are dominant in the Shagar sand zone and show the highest potential zones in the Kareem Formation. On the other hand, quartz lithic arenite and calcareous lithic arenite constitute the major microfacies in the Rahmi clastic zone and show the lowest reservoir quality. The main diagenetic processes that enhance the sandstone reservoir intervals of the Kareem Formation are the microfracturing of mineral grains and the dissolution of both feldspar and carbonate cement. In contrast, the amount of cementing materials, particularly authigenic carbonate and clay cements, led to diminishing of the reservoir quality of the studied Kareem Formation.

Geophysical 3D-static reservoir and basin modeling of a Jurassic estuarine system (JG-Oilfield, Abu Gharadig basin, Egypt)

• The estuarine architecture is just depicted via facies-constrained 3D modeling. • Heterogeneity of Khatatba complex reveals five sedimentary facies associations. • Basin modeling confirms hydrocarbon charging from Khatatba shales to reservoirs. • Bars comparison with modern-ancient analogues verifies sufficient characteristics. • Given best reservoir quality, estuarine bars deserve testing in similar settings. Inadequate delineation of reservoir-heterogeneities, along with charge-timing confirmation, can considerably mislead exploration-development phases of petroleum. Therefore, precisely depicting the reservoir-architecture is crucial for avoiding exploration failures. To this end, integrated approach of various facies analysis and modeling-related disciplines; e.g. seismic facies, and GR-log motifs; was applied, in this study, to develop a depositional-model capable of aiding in stochastically-mapping reservoir heterogeneity and quality of the Jurassic estuarine depositional-system at JG-Field. To overcome the issue of sparse well control and scarcity of promising discoveries from deep-buried intervals in the study area, stochastic 3D-geocellular reservoir modeling, constrained by seismic attribute analysis, was performed to render a lateral prediction of different facies constituting the Jurassic succession. Predicting organic maturities and retrieving past geologic processes controlled sedimentary basin evolution were also a matter of importance to confirm hydrocarbon-charging to reservoir intervals. Accordingly, 1D-basin model was established so as to complete the story of petroleum system analysis in the area. We utilized dataset of seismic, log, core, and thin-section data; and applied both object-based and pixel-based, SIS (Sequential Indicator-Simulation) and SGS (Sequential Gaussian-Simulation), stochastic modeling algorithms upon simulating rock and fluid properties. The results show that the Jurassic succession constitutes a third-order depositional sequence of fluvio-estuarine units, subdivided into five sedimentary facies-associations. Fluvial and tidal-bar facies associations enrich medium-grained sandstones, deposited in subaerial and subaqueous conditions respectively, featuring significant reservoir quality. Given best reservoir-quality, and considerable thickness, the tidal sand-bars ought to catch attention of future development strategies and be considered for investigation in similar settings.

Case Study: Smart Liner Matrix-Acid Stimulation—A Cost-Effective Performance-Enhancement Technique for Carbonate Reservoirs

Carbonate reservoirs require effective acid stimulation to improve well productivity. For long horizontal wells, a complicating factor has previously been the difficulty of controlling acid placement along the reservoir section. The Smart Liner (SL) concept solves this problem. It consists of a number of small holes spaced in such a way so as to distribute acid evenly along the reservoir interval. Fig. 1 shows a schematic of the concept. Without the need of a coiled tubing, acid is bull-headed at a high rate from surface through the production tubing and enters the liner from the left. The liner does not have to be horizontal but very often is. When acid reaches the first hole, which typically has a diameter of 3–6 mm, the pressure drop across the hole is so large that only a small portion of the acid exits the liner through the hole; the remaining acid continues along the liner until it reaches the next hole where the process is repeated. Appropriate hole spacing ensures that acid is distributed with a given acid coverage (dosage) in barrels of acid per foot of reservoir section. The small cross-sectional area of the holes results in focused acid jetting at velocities often exceeding 20 m/s (65 ft/s). The jetting helps promote wormhole formation leading to substantial productivity enhancement. The hole-spacing design requires dedicated software which must take into consideration constraints pertaining to the reservoir, the well, and the pumping equipment while minimizing operational complexity. The tool should also yield a quick answer to enable the user to optimize the final design post drilling and provide a running tally consisting of the sequence of liner joints to be run in hole. In heterogeneous reservoirs, it is typically required to segment the wellbore with swellable packers to isolate sections with different reservoir pressure and/or fluid mobility, and the SL concept readily accommodates that. Also, since the subsequent stimulation relies on matrix acidization, the tool must ensure that fracturing pressures are not exceeded. The original limited-entry liner (LEL) technique dates to the early 1960s and was proposed for fracturing applications (SPE 530). Reviews by Somanchi et al. (SPE 184834) and Weddle et al. (SPE 189880) suggest that it is still widely applied for such purposes. In the late 1990s, Maersk Oil adapted the concept to effectively stimulate extended-reach wells in its North Sea chalk reservoirs on a large scale. Hansen and Nederveen (SPE 78318) refer to the technology as controlled acid jetting (CAJ). In the following years, the CAJ technique was implemented in more difficult formations such as a 0.1 mD chalk reservoir (SPE 144159) as well as in a tight, gas-bearing formation (SPE 123979). Balsawer et al. (IPTC 17611) designed multizone completions in ultralong wells in a giant field offshore Qatar, which comprised more heterogeneous limestone formations. Other field implementations have been described by Issa et al. (SPE 171779) for a super-giant reservoir offshore Abu Dhabi. Past deployments have concentrated on extended-reach wells with reservoir temperatures up to 210°F. Over the past year, ADNOC has significantly expanded the operational envelope of the Smart Liner concept. Fig. 2 summarizes the variation in completed reservoir length and average permeability for 80 well designs. Table 1 shows that reservoir temperatures vary from 140°F to 300°F.

Reservoir characterization of fluvio-deltaic sandstone packages in the framework of depositional environment and diagenesis, the south Caspian Sea basin

The Middle Pliocene Fasila and Balakhany Suites are important petroleum-bearing reservoirs in the South Caspian Basin. There are four lithofacies associated with the interbedded sandprone reservoir intervals. The mineral constituents, sedimentary structures and depositional setting of the productive interval are interpreted as river-dominated depositional setting, including conglomeratic facies relating to a channel floor sub-environment and sandstone facies associated with the upper parts of river channels. The drainage basin of the Volga River is considered as the provenance for these deposits derived from basement rock outcrops to the north, which belongs to the Russian Precambrian semi-oceanic continental platform. Reservoir quality is assessed using the core-based porosity and permeability data in relation to the sedimentary and diagenetic processes influencing each lithofacies. Lithofacies 1 and 2 have good reservoir quality, while lithofacies 3 and 4 have poorer reservoir quality. Reservoir quality is controlled by both depositional setting (grain size and texture) and diagenetic imprints associated mainly with compaction, cementation and neumorphism. The role of clay minerals in the diagenesis of the sandstones with increasing burial depth is revealed by SEM and XRD analysis. Clay minerals progressively alter to illite, smectite and chlorite with increasing burial depth. This alteration leads to the occlusion of pore throats and degrading reservoir permeability.

Lithofacies classification and sequence stratigraphic description as a guide for the prediction and distribution of carbonate reservoir quality: A case study of the Upper Cretaceous Khasib Formation (East Baghdad oilfield, central Iraq)

In the East Baghdad oilfield of central Iraq, the Upper Cretaceous Khasib Formation is the largest producing carbonate reservoir. The basic architecture of the “Khasib reservoirs” is heavily impacted by the lithofacies classification and sequence stratigraphic interpretation at East Baghdad field. A description of the Khasib Formation in terms of depositional systems, environments and lithofacies was obtained by studying the vertical distribution of the lithofacies, defined using well-log values and their mutual statistical relationships and constrained by the core data (thin sections). In this paper, a lithofacies classification and sequence stratigraphic interpretation are used to define reservoir geometry, lateral continuity and petrophysical characteristics of the Khasib reservoirs. The “Khasib” carbonate ramp stratigraphy exhibits different lithofacies in different depositional systems at the East Baghdad field. In addition, the log signatures and petrophysical properties of the same lithofacies vary. Multivariate statistical methods (principal component analysis and clustering) have been applied to separate stratigraphic packages and different carbonate lithofacies. Khasib carbonate lithofacies can be better discriminated from cluster analysis based on principal components rather than from arbitrary well log observations alone. The geometry of the strata in the ‘Khasib’ outer ramp is retrogradational, becoming aggradational during the lowstand systems tract (LST) and transgressive systems tract (TST). The highstand systems tract (HST) of the Khasib Formation is typically distinguished by a relatively thick aggradational-to-progradational geometry. This parasequence set is widespread upon the “Khasib” mid- and inner ramp. Petrographic analysis reveals the relative abundance and distribution of characteristic porosity types of the “Khasib” reservoirs. The HST (mid- and inner ramp) of “Khasib” Formation reveals the best reservoir characteristics (thickness, porosity, and hydrocarbon saturation) in the East Baghdad field. This enhancement of the knowledge of the lithofacies within a sequence stratigraphic framework through the application of principal component and cluster analysis is especially important to -optimally delineate and define the potential reservoir intervals of Iraq's Khasib Formation. Such multivariate statistical techniques may have similar beneficial application to carbonate reservoirs elsewhere in the world.

A new method to predict brittleness index for shale gas reservoirs: Insights from well logging data

Brittleness is a significant mechanical property which determines the degree of fracturing difficulty in shale gas exploitation and hence, the brittleness index (BI) is a key parameter for the selection of suitable hydraulic fracturing intervals in shale gas reservoirs. However, at present there are no universal and convenient methods for the prediction of BI. Therefore, this study proposes a well logging data-driven BI prediction method based on principal component analysis (PCA) and back-propagation neural networks (BPNN), which can interpret nonlinear and complex relationships between predictors (input variables) and predicted values (target variables). Specifically, 63 samples and their corresponding well logging data were collected from the Wufeng-Longmaxi and Baota formations at the periphery of Sichuan Basin. Experimentally measured brittleness index (BIcore) values (from 0.18 to 0.88) derived from compression test stress-strain curves, were considered as the target parameter. Based on the results of linear regression and sensitivity analysis, five types of well logging, including gamma ray (GR), density (DEN), compressional wave slowness (DT), neutron porosity (CNL) and spontaneous potential (SP), were selected as appropriate well logging techniques. Three principal components were extracted from the five well logging datasets using PCA. Following PCA, the back-propagation neural network (PCA-BPNN) model exhibited excellent prediction accuracy according to statistical and graphical error analysis. The established PCA-BPNN model was then applied to forecast the BI profiles of the intervals of interest in well Y1 in the study area and the predicted BI values were found to be in agreement with the laboratory measured BIcore values. Therefore, the established PCA-BPNN BI prediction method can be applied to accurately locate suitable hydraulic fracturing intervals for economic and technical practicality.

An integrated high-resolution image log, sequence stratigraphy and palynofacies analysis to reconstruct the Albian – Cenomanian basin depositional setting and cyclicity: Insights from the southern Tethys

Borehole image logs are used to overcome the lack of core samples and other conventional open-hole logs in many subsurface reservoirs around the world, significantly reducing the likelihood of petroleum resource exploration. These image logs can provide high-resolution data to visualize sedimentary structures, facies types, lithofacies, geomechanical characteristics, and depositional trends. Sedimentologists recognize the Bahariya Formation of the North-Western Desert of Egypt as the typical coastal -shallow marine depositional model that emphasizes a typical heterogeneous sandstone reservoir with many obstacles in production profile. One of the most significant issues related to the heterogeneous Bahariya reservoir that confronts hydrocarbon producers is the loss of productive target zones due to spatial facies changes. This research aims to overcome the exploration and development challenges of the complex and heterogeneous sandstone reservoir of the Albian – Cenomanian Bahariya Formation that lies in the Abu Gharadig Basin, Southern Tyths, Egypt. In this work, we used integrated image logging in conjunction with palynofacies, core samples, and sequence stratigraphy to provide high resolution information that can aid in better resource exploitation. Furthermore, we utilized the integrated work in the definition of the high-resolution para-sequences, sequences boundaries, lithofacies characteristics and paleocurrent analysis of each facies association. The interpretation of coastal shallow marine facies from four BHI-logs was established and calibrated with two core sets in order to define the best hydrocarbon reservoir intervals and focus on improving the development plan of the study area. Our findings show that the Bahariya Formation is characterized by eleven facies associations which have been interpreted based on the integrating of the twenty-seven electrofacies extracted from the FMI images, wireline logs, and core photographs. The identified facies associations were classified into five depositional sequences and their boundaries were determined using dipmeter patterns and extracted lithofacies from BHI. The LST and MFS deposits in both the fourth and fifth depositional cycles, respectively, whereas the HST deposits are found only in the third depositional cycle. According to our findings, the development of the shoreface sandy facies of cycles three and five represents the maximum rate of sea-level rise, as well as the development of the offshore sand bar system, which represents high-quality sandstone reservoirs. This case study demonstrates how image logs can be used to better understand the spatial distribution and geometries of sandstone bodies in the Bahariya Formation. Furthermore, it provides a reference imaging fingerprint of high-resolution coastal shallow marine, high-frequency sequences analysis, sedimentary structures, and extracted electrofacies analogues that can be used in the basin and elsewhere.

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

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.

Determination of the mud weight window, optimum drilling trajectory, and wellbore stability using geomechanical parameters in one of the Iranian hydrocarbon reservoirs

The challenges behind this research were encountered while drilling into the Ilam, Mauddud, Gurpi, and Mishrif Formations, where severe drilling instability-related issues were observed across the weaker formations above the reservoir intervals. In this paper, geomechanical parameters were carried out to determine optimum mud weight windows and safe drilling deviation trajectories using the geomechanical parameters. We propose a workflow to determine the equivalent mud window (EMW) that resulted in 11.18–12.61 ppg which is suitable for Gurpi formation and 9.36–13.13 ppg for Ilam and Mishrif Formations, respectively. To estimate safe drilling trajectories, the Poisson’s ratio, Young’s modulus, and unconfined compressive strength (UCS) parameters were determined. These parameters illustrate an optimum drilling trajectory angle of 45° (Azimuth 277°) for the Ilam to Mauddud Formations and less than 35° for the Gurpi Formation. Our analysis reveals that maximum horizontal stress and Poisson’s ratio have the most impact on determining the optimum drilling mud weight windows and safe drilling deviation trajectories. On the contrary, vertical stress and Young’s modulus have minimum impact on drilling mud weight windows and safe drilling deviation trajectories. This study can be used as a reference for the optimal mud weight window to overcome drilling instability issues in future wellbore planning in the study.

Improved gas sand facies classification and enhanced reservoir description based on calibrated rock physics modelling: A case study

Abstract Rock physics provides a dynamic tool for quantitative analysis by developing the basic relationship between fluid, lithological, and depositional environment of the reservoir. The elastic attributes such as impedance, density, velocity, V p/V s ratio, Mu-rho, and Lambda-rho are crucial parameters to characterize reservoir and non-reservoir facies. Rock physics modelling assists like a bridge to link the elastic properties to petrophysical properties such as porosity, facies distribution, fluid saturation, and clay/shale volume. A robust petro-elastic relationship obtained from rock physics models leads to more precise discrimination of pay and non-pay facies in the sand intervals of the study area. The Paleocene aged Lower Ranikot Formation and Pab sandstone of Cretaceous age are proven reservoirs of the Mehar gas field, Lower Indus Basin. These sands are widely distributed in the southwestern part of the basin and are enormously heterogeneous, which makes it difficult to distinguish facies and fluid content in the reservoir intervals. So, an attempt is made in this paper to separate the reservoir facies from non-reservoir facies by using an integrated approach of the petro-elastic domain in the targeted sand intervals. Furthermore, missing logs (S-sonic and P-sonic) were also synthesized in the wells and missing intervals along with improving the poor quality of the density log by captivating the washouts and other side effects. The calibrated rock physics model shows good consistency between measured and modelled logs. Petro-elastic models were predicted initially using petrophysical properties and incorporated at true reservoir conditions/parameters. Lithofacies were defined based on petrophysical cut-offs. Rock physics modelled elastic properties (Lambda-rho versus Mu-rho, impedance versus V p/V s ratio) were then cross-plotted by keeping lithofacies in the Z-axis. The cross-plots clearly separated and demarcated the litho-fluid classes (wet sand, gas sand, shale, and limestone) with specific orientation/patterns which were randomized in conventional petrophysical analysis.

Geostatistics assisted by machine learning for reservoir property modeling: A case study in presalt carbonates of Buzios Field, Brazil

An embedded model estimator (EMBER) petrophysical modeling algorithm has been applied to obtain effective porosity and permeability within the presalt carbonate reservoirs of the Barra Velha Formation in Buzios Field, Santos Basin. This advanced methodology was used due to the heterogeneity and complexity of the reservoirs, which makes modeling by conventional geostatistical methodologies difficult. For effective porosity modeling, we chose one facies model, one stratigraphic seismic attribute (acoustic impedance), and one structural seismic attribute (local flatness) as secondary variables. Permeability was modeled by using the best effective porosity simulation result as a secondary variable. Our results demonstrate that average effective porosity and permeability were 0.10 v/v and 440 md, respectively, indicating good reservoir quality throughout the studied area. A vertical trend of high effective porosities and permeabilities for the basal and uppermost reservoir sections was identified in our results, as well as a trend with lower values for these reservoir properties for the intermediate reservoir section. The lower section of the formation presented more continuity, and we infer it to be the best reservoir interval. We observed two horizontal trends for these reservoir properties at the formation top: one of higher values aligned to the north–south direction at the structural highs and another of lower reservoir properties related to isolated structural lows within structural highs. Correlation between modeled results and the blind test ANP-1 well upscaled properties was high, and upscaled well-log property distributions were preserved in the EMBER simulations, proving the predictive capacity of the algorithm. Finally, conditional distributions analysis indicated that the basal section of the Barra Velha Formation presents higher uncertainty for the estimation of effective porosity. Even though this interval is considered to have the best reservoir characteristics, decision making should be done with caution for this section.

Seismic stratigraphy, sedimentary facies analysis and reservoir characteristics of the Middle Jurassic syn-rift sediments in Salam Oil Field, north Western Desert, Egypt

The Middle Jurassic syn-rift sediments (Khatatba Formation) of the Western Desert, Egypt hosting potential reservoir intervals are prospective targets for hydrocarbon exploration and development campaigns. However, their depositional evolution and factors controlling distribution of the best reservoir faces are not very well-constrained. This work integrates seismic, well logs and conventional core dataset in order to define the syn-rift sedimentary patterns and their impact on distribution and quality of the reservoir facies. Khatatba Formation comprises two discrete units; the lower unit constitutes lower progradational and upper retrogradational sedimentary packages that are interpreted in terms of discrete rift phases. Nine sedimentary facies associations (FA) were recognized and their stacking patterns are governed by the rift evolution and the interplay between variation in fault offsets and sediment supply. Distal sand bar sandstones, marine shales and organic-rich shales were accumulated during periods of high subsidence. Successive alternation between shallow and deep facies at the base of the lower unit reveals repeated short periods of progradation and retrogradation with an overall progradational trend reflecting an elevated rate of sediment supply.Episodic fault-controlled retrogradation and progradation continued during the deposition of the Khatatba upper unit where the progradational deltaic facies changes upward into retrogradational marine sediments and aggradational-progradational aeolian and shoreface sandstones. Five hydraulic flow units (HFUs) were identified and their distribution is mostly controlled by the rift evolution. The lowest reservoir quality HFU4 and HFU5 are often associated with the retrograding distal facies accumulated during highest rates of subsidence. These zones do not contribute to more than 10% of the reservoir flow capacity. On the other hand, the progradational deltaic facies accounts for approximately 85% of the reservoir flow capacity in both lower and upper Khatatba units.

Natural fractures and discontinuities in a Lower Cretaceous chalk-marlstone reservoir, Valdemar Field, Danish North Sea

Natural fractures and discontinuities have significant impact on subsurface flow conditions and thus production, of carbonate reservoirs, particularly in low-permeability sediments such as chalk-marl successions characterizing the Lower Cretaceous reservoirs in the Danish North Sea. Yet the diversity and distribution of the fractures are often poorly understood and largely underestimated. In heterogeneous, tight carbonate reservoirs, natural fractures can enhance permeability, as well as create secondary porosity and promote connectivity between reservoir compartments. The Valdemar Field, Danish Central Graben, represents the only producing field from the Lower Cretaceous in the Danish sector of the North Sea. The main reservoirs are confined to the Tuxen and Sola Formations. A new reservoir zonation is proposed based on facies characteristics and fracture patterns to consist of the lower Tuxen, middle-upper Tuxen, lower-middle Sola and upper Sola units with the Munk Marl Bed and Fischshiefer Member forming major reservoir barriers between the lower and the middle-upper Tuxen, and the lower-middle and the upper Sola units, respectively.The reservoir intervals are of heterogeneous nature and composed of interbeds of five main facies comprising chalk, slightly marly chalk, marly chalk, chalky marlstone and marlstone. Six types of natural fractures and discontinuities are identified in the Valdemar Field based on core studies: cemented fractures, deformation bands, open fractures with plumose structures and hackle marks, shear fractures, small-offset shear fractures and rubble zones. The most dominant fracture type within all facies is the open fractures with plumose structure and hackle marks followed by small-offset shear fractures, shear fractures and rubble zones. Cemented fractures and deformation bands are less dominant. The small-offset shear fractures, shear fractures and open fractures with plumose structures and hackle marks are flow enhancing, while the cemented fractures and deformation bands are neutral or flow reducing. Rubble zones are also recorded throughout the core material. If these represent naturally fractured zones, present under subsurface conditions, they would be strongly flow enhancing. The flow-enhancing natural fractures (open fractures, shear fractures and small offset shear fractures) have densities of 7.2/m in the chalk, 5.0/m in slightly marly chalk, 3.1/m in marly chalk, 4.8/m in the chalky marlstone while they are absent in the marlstone. The flow-enhancing fractures have densities of 4.6/m in the lower Tuxen reservoir, 4.0/m in the middle-upper Tuxen reservoir, 2.7/m in the lower-middle Sola reservoir, and 7.4/m in the upper Sola reservoir. This study provides a detailed analysis of the natural fractures and discontinuities occurring the Lower Cretaceous succession of the Danish North Sea Basin, and their relation to the sedimentary facies and reservoir units.

Morphology and evolution of submarine canyons on the northwest South China Sea margin

Submarine canyons are observed along both passive and active continental margins, but the factors controlling their complex morphology are still poorly understood. Here, we use high-resolution multibeam bathymetric and 2D seismic data to investigate an area of the northwest South China Sea in which 48 submarine canyons are identified. These previously unstudied submarine canyons incise the continental shelf, being located at a water depth between 200 m and 2200 m. Canyon morphology varies from southwest to northeast, namely in what their length and incision depth are concerned. We therefore divide these canyons into four main types: a) Types A, B and C showing a predominant NW-SE direction, and b) Type D canyons striking to the north. By analysing their internal architectures, we propose that submarine canyons along the northwest South China Sea margin were initiated in the Late Miocene by retrogressive slope failure in response to the gradual build-up of sediment on the continental slope. Differences in sediment supply and fault activity are recognised here as the main factors controlling the morphology of the investigated submarine canyons. In addition, recurrent mass-transport deposits (MTDs) fed sediment from the northwest South China Sea margin into the study area, accelerating the filling of the Central Canyon system, a giant submarine canyon located to the south of the investigated continental slope. The discovery of gas fields (LS22–1, LS17–2) and a gas hydrate drilling zone (GMGS5) in the Central Canyon system proves that MTDs comprise good reservoir intervals. Our results contribute to a better understanding of the origin and development of submarine canyons and highlight the role of sediment supply and tectonic events in controlling canyon morphology.

Gas-dynamic characteristics of the host rocks of Mir pipe mine field deep horizons

The purpose of the research is to study the gas-dynamic characteristics of deep horizons of the Mir pipe mine field to ensure industrial safety under construction and production resumption at the field. The study is based on the interval field experiments carried out during drilling and subsequent study of the core. The main gas-dynamic parameters of the deep horizons of the field were studied during the drilling of pilot wells that enabled to perform interval determination of the flow rates of formation gases using packers and complex research equipment, gas sampling for the determination of chemical composition of gases, and gas logging. The conducted works resulted in the formulation of the gas-dynamic characteristic of the Tolbachan formation within the mine field of the Mir pipe. Reservoir intervals were identified and the nature of their fluid saturation was determined. The chemical composition of formation gases was clarified and gas release nature and intensity were studied both under drilling and interval testing. The result of the research carried out was identification of zones with different fluid manifestations, as well as comparison of the field under investigation with the previously studied International pipe. The results of the conducted research works will form the basis for performing design forecast calculations, as well as for making the main design decisions under construction of capital mine workings, especially in terms of advanced degassing of the mountain range. Consideration of the zones identified within the Tolbachan formation, which feature different nature of fluid saturation, will allow to take into account and minimize possible adverse factors.

Scoresbysund Composite Tectono-Sedimentary Element, East Greenland Rifted Margin, Denmark Strait

Abstract The little explored central East Greenland margin contains thick sedimentary accumulations confined within the Scoresbysund Basin. The geological evolution of the area distinguishes it from other parts of East Greenland. Even so, resemblances with the prospective basins onshore and offshore further north probably exist, and the margin may hold real petroleum potential. The Scoresbysund Composite Tectono-Sedimentary Element (CTSE) delineates the oldest part of the Scoresbysund Basin. It formed through multiple phases of rifting, volcanism, uplift and thermal subsidence between Devonian and Miocene times. The development of the CTSE concluded with the latest Oligocene or early Miocene continental break-up of the Jan Mayen microcontinent and East Greenland. The Scoresbysund CTSE contains approximately 4 km of Eocene–lower Miocene fan-delta deposits that accumulated during downfaulting along the East Greenland Escarpment and which further seawards intercalate with basalts. The fan-delta deposits rest on Paleocene basalts that most probably cover Paleozoic–Mesozoic strata. Equivalent to onshore, the deeply buried section probably includes source rock and reservoir intervals of Carboniferous, Permian and Mesozoic age. Together with the major fault structures existing in the western part of the area, this may form the basis for a working petroleum system.

Charakterystyka złoża oparta na metodzie Lambda-Mu-Rho – przykład analizy

The results of analyzes based on the Lambda-Mu-Rho method, allow us to understand how the properties of a formation are related to each other, identify lithological and petrophysical variability, recognise zones of saturation with hydrocarbons, and in the next stage, to integrate these results with seismic data. Consequently, various parameters of the deposit are considered (lithological, petrophysical, geochemical, geomechanical) and their waveform response whose interrelations can be observed in different scales of observation, giving the most reliable and coherent picture of the analyzed area. The aim of the article is to present the possibility of lithological and parametric identification using the LMR method, as well as attempt to determine the sweet spot for the shale reservoir interval. Lamé parameters (λρ and μρ) analysis supports the inference regarding relations between elastic moduli and individual parameters as well as lithology and fluid discrimination. Numerous publications have confirmed the validity of applying the LMR method due to the reliability of the obtained results. In our work, several relationships between velocity of compressional (Vp) and shear (Vs) waves, density, Lambda-Rho (λρ), Mu-Rho (μρ), brittleness index (BI) and total organic content (TOC) were analyzed. The anonymous analyzing area covers five formations associated with limestones and shales rocks. This article concerns the general characteristic of these formations, including two of them which accumulate hydrocarbons from the same petroleum system. A number of dependencies between the analyzed elastic parameters as well as brittleness and organic matter content were determined, as well as a threshold value for the Vp /Vs ratio, defining the hydrocarbon accumulation zones. Finally, the analysis results were applied in the 3D model, locating the hydrocarbon accumulation zones within one of the analyzed formations.

Integration of sequence stratigraphy, rock physics and AI inversion to determine the prospective reservoir in the shelf environment of the Tarakan Basin, Indonesia

The Tarakan Basin is one hydrocarbon basin in Indonesia with approximately 40 discoveries and more than 1000 MBOE reserves. This study discusses an approach to integrate the sequence stratigraphy, rock physics and acoustic impedance (AI) inversion analysis to determine the prospective reservoirs in the basin. PRG-1 well data is used in the sequence stratigraphy and rock physic analysis. The sequence stratigraphy analysis of PRG-1 shows that there are three system tracts: transgressive, low stand tract and high stand system tracts. The integration of sequence stratigraphy, rock physics and log data analysis show that the prospective reservoir interval in PRG-1 well is located at a depth of 4730-4780 feet. It is characterized by low gamma ray, low NPHI, low density and high resistivity. The prospective interval was deposited in early Pliocene as Tarakan Formation in the low stand system tract of shelf depositional environment. The AI map shows that the distribution of the prospective is around the PRG-1 and in the eastern part of the area.